NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
Organization
Enable Midstream Partners, LP is a Delaware limited partnership whose assets and operations are organized into
two
reportable segments: (i) gathering and processing and (ii) transportation and storage. The gathering and processing segment primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers. The transportation and storage segment provides interstate and intrastate natural gas pipeline transportation and storage services primarily to our producer, power plant, LDC and industrial end-user customers. The Partnership’s natural gas gathering and processing assets are primarily located in Oklahoma, Texas, Arkansas and Louisiana and serve natural gas production in the Anadarko, Arkoma and Ark-La-Tex Basins. Crude oil gathering assets are located in Oklahoma and serve crude oil production in the SCOOP and STACK plays of the Anadarko Basin and in North Dakota and serve crude oil production in the Bakken Shale formation of the Williston Basin. The Partnership’s natural gas transportation and storage assets consist primarily of an interstate pipeline system extending from western Oklahoma and the Texas Panhandle to Louisiana, an interstate pipeline system extending from Louisiana to Illinois, an intrastate pipeline system in Oklahoma, and our investment in SESH, a pipeline extending from Louisiana to Alabama.
CenterPoint Energy and OGE Energy each have
50%
of the management interests in Enable GP. Enable GP is the general partner of the Partnership and has no other operating activities. Enable GP is governed by a board made up of
two
representatives designated by each of CenterPoint Energy and OGE Energy, along with the Partnership’s Chief Executive Officer and
three
independent board members CenterPoint Energy and OGE Energy mutually agreed to appoint. CenterPoint Energy and OGE Energy also own a
40%
and
60%
interest, respectively, in the incentive distribution rights held by Enable GP.
As of
March 31, 2019
, CenterPoint Energy held approximately
53.8%
or
233,856,623
of the Partnership’s common units, and OGE Energy held approximately
25.5%
or
110,982,805
of the Partnership’s common units. Additionally, CenterPoint Energy holds
14,520,000
Series A Preferred Units. The limited partner interests of the Partnership have limited voting rights on matters affecting the business. As such, limited partners do not have rights to elect the Partnership’s general partner on an annual or continuing basis and may not remove Enable GP, its current general partner, without at least a
75%
vote by all unitholders, including all units held by the Partnership’s limited partners, and Enable GP and its affiliates, voting together as a single class.
As of
March 31, 2019
, the Partnership owned a
50%
interest in SESH. See Note 8 for further discussion of SESH. For the
three months ended
March 31, 2019
, the Partnership held a
50%
ownership in Atoka and consolidated Atoka in its Condensed Consolidated Financial Statements as EOIT acted as the managing member of Atoka and had control over the operations of Atoka. In addition, beginning November 1, 2018 through
March 31, 2019
, the Partnership owned a
60%
interest in ESCP, which is consolidated in its Condensed Consolidated Financial Statements as EOCS acted as the managing member of ESCP and had control over the operations of ESCP.
Basis of Presentation
The accompanying condensed consolidated financial statements and related notes of the Partnership have been prepared pursuant to the rules and regulations of the SEC and GAAP. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with GAAP have been omitted. The accompanying condensed consolidated financial statements and related notes should be read in conjunction with the consolidated financial statements and related notes included in our Annual Report.
The condensed consolidated financial statements and the related notes reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position and results of operations for the respective periods. Amounts reported in the Partnership’s Condensed Consolidated Statements of Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests.
For a description of the Partnership’s reportable segments, see Note 16.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Depreciation Expense
The Partnership completed a depreciation study for the Gathering and Processing and Transportation and Storage segments. Effective January 1, 2019, the new depreciation rates have been applied prospectively as a change in accounting estimate. The new depreciation rates did not result in a material change in depreciation expense or results of operations.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable are recorded at the invoiced amount and do not typically bear interest. The determination of the allowance for doubtful accounts requires management to make estimates and judgments regarding our customers’ ability to pay. The allowance for doubtful accounts is determined based upon specific identification and estimates of future uncollectable amounts. On an ongoing basis, we evaluate our customers’ financial strength based on aging of accounts receivable, payment history, and review of other relevant information, including ratings agency credit ratings and alerts, publicly available reports and news releases, and bank and trade references. It is the policy of management to review the outstanding accounts receivable at least quarterly, giving consideration to credit losses, the aging of receivables, specific customer circumstances that may impact their ability to pay the amounts due and current and forecasted economic conditions over the assets contractual lives. Based on this review, management determined that a
$2 million
allowance for doubtful accounts was required at
March 31, 2019
and
December 31, 2018
.
Inventory
Natural gas inventory is held, through the transportation and storage segment, to provide operational support for the intrastate pipeline deliveries and to manage leased intrastate storage capacity. Natural gas liquids inventory is held, through the gathering and processing segment, due to timing differences between the production of certain natural gas liquids and ultimate sale to third parties. Natural gas and natural gas liquids inventory is valued using moving average cost and is subsequently recorded at the lower of cost or net realizable value. The Partnership’s Inventory balance is net of
$1 million
and
$4 million
lower of cost or net realizable value adjustments as of
March 31, 2019
and
December 31, 2018
, respectively.
(2) New Accounting Pronouncements
Accounting Standards to be Adopted in Future Periods
Financial Instruments—Credit Losses
In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This standard requires entities to measure all expected credit losses of financial assets held at a reporting date based on historical experience, current conditions, and reasonable and supportable forecasts in order to record credit losses in a more timely manner. ASU 2016-13 also amends the accounting for credit losses on available-for-sale debt securities and purchased financial assets with credit deterioration. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted for interim and annual periods beginning after December 15, 2018. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.
Intangibles—Goodwill and Other
In January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment.” This standard requires entities to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. The standard is effective for interim and annual reporting periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.
Fair Value Measurement—Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement
In August 2018, the FASB issued ASU No. 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement” which focuses on improving the effectiveness of disclosures in the notes to the financial statements by facilitating clear communication of the information required by U.S. GAAP that is most important to users of each entity’s financial statements. The standard is effective for interim and annual reporting periods beginning after December 15, 2019, although early adoption is permitted. The Partnership expects to adopt these standards in the first quarter of 2020 and continues to evaluate the other impacts of the new standards on our Condensed Consolidated Financial Statements and related disclosures.
Intangibles—Goodwill and Other—Internal-Use Software
In August 2018, the FASB issued ASU No. 2018-15, “Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”, which aims to reduce complexity in the accounting for costs of implementing a cloud computing service arrangement. ASU No. 2018-15 aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.
Collaborative Arrangements
In November 2018, the FASB issued ASU No. 2018-18, “Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606.” This standard resolves the diversity in practice concerning the manner in which entities account for transactions on the basis of their view of the economics of the collaborative arrangement. The amendments (1) clarify that certain transactions between collaborative participants should be accounted for as revenue under topic 606 when the collaborative participant is a customer in the context of the unit of account; (2) add unit-of-account guidance in Topic 808 to align with the guidance in Topic 606; and (3) clarify that in a transaction that is not directly related to sales to third parties, presenting the transaction as revenue would be precluded if the collaborative participant counterparty was not a customer. The standard is effective for interim and annual periods beginning after December 15, 2019. The Partnership does not expect the adoption of this standard to have a material impact on our Condensed Consolidated Financial Statements and related disclosures.
(3) Revenues
The following tables disaggregate total revenues by major source from contracts with customers and the gain (loss) on derivative activity for the
three months ended March 31, 2019
and
2018
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2019
|
|
Gathering and
Processing
|
|
Transportation
and Storage
|
|
Eliminations
|
|
Total
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Revenues:
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
Natural gas
|
$
|
128
|
|
|
$
|
162
|
|
|
$
|
(141
|
)
|
|
$
|
149
|
|
Natural gas liquids
|
270
|
|
|
6
|
|
|
(6
|
)
|
|
270
|
|
Condensate
|
34
|
|
|
—
|
|
|
—
|
|
|
34
|
|
Total revenues from natural gas, natural gas liquids, and condensate
|
432
|
|
|
168
|
|
|
(147
|
)
|
|
453
|
|
Gain (loss) on derivative activity
|
(9
|
)
|
|
(1
|
)
|
|
—
|
|
|
(10
|
)
|
Total Product sales
|
$
|
423
|
|
|
$
|
167
|
|
|
$
|
(147
|
)
|
|
$
|
443
|
|
Service revenues:
|
|
|
|
|
|
|
|
Demand revenues
|
$
|
60
|
|
|
$
|
131
|
|
|
$
|
—
|
|
|
$
|
191
|
|
Volume-dependent revenues
|
147
|
|
|
18
|
|
|
(4
|
)
|
|
161
|
|
Total Service revenues
|
$
|
207
|
|
|
$
|
149
|
|
|
$
|
(4
|
)
|
|
$
|
352
|
|
Total Revenues
|
$
|
630
|
|
|
$
|
316
|
|
|
$
|
(151
|
)
|
|
$
|
795
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2018
|
|
Gathering and
Processing
|
|
Transportation
and Storage
|
|
Eliminations
|
|
Total
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Revenues:
|
|
|
|
|
|
|
|
Product sales:
|
|
|
|
|
|
|
|
Natural gas
|
$
|
106
|
|
|
$
|
131
|
|
|
$
|
(109
|
)
|
|
$
|
128
|
|
Natural gas liquids
|
279
|
|
|
7
|
|
|
(7
|
)
|
|
279
|
|
Condensate
|
36
|
|
|
—
|
|
|
—
|
|
|
36
|
|
Total revenues from natural gas, natural gas liquids, and condensate
|
421
|
|
|
138
|
|
|
(116
|
)
|
|
443
|
|
Gain (loss) on derivative activity
|
(3
|
)
|
|
2
|
|
|
1
|
|
|
—
|
|
Total Product sales
|
$
|
418
|
|
|
$
|
140
|
|
|
$
|
(115
|
)
|
|
$
|
443
|
|
Service revenues:
|
|
|
|
|
|
|
|
Demand revenues
|
$
|
50
|
|
|
$
|
120
|
|
|
$
|
—
|
|
|
$
|
170
|
|
Volume-dependent revenues
|
123
|
|
|
19
|
|
|
(7
|
)
|
|
135
|
|
Total Service revenues
|
$
|
173
|
|
|
$
|
139
|
|
|
$
|
(7
|
)
|
|
$
|
305
|
|
Total Revenues
|
$
|
591
|
|
|
$
|
279
|
|
|
$
|
(122
|
)
|
|
$
|
748
|
|
Accounts Receivable
The table below summarizes the change in accounts receivable for the
three months ended March 31, 2019
.
|
|
|
|
|
|
|
|
|
|
March 31,
2019
|
|
December 31,
2018
|
|
|
|
|
|
(In millions)
|
Accounts Receivable:
|
|
|
|
Customers
|
$
|
259
|
|
|
$
|
297
|
|
Contract assets
(1)
|
14
|
|
|
6
|
|
Non-customers
|
5
|
|
|
6
|
|
Total Accounts Receivable
(2)
|
$
|
278
|
|
|
$
|
309
|
|
____________________
|
|
(1)
|
Contract assets reflected in Total Accounts Receivable include accrued minimum volume commitments. Contract assets increased
$8 million
compared to December 31, 2018 primarily due to the increase in estimated shortfall volumes on certain annual minimum volume commitment arrangements. Total Accounts Receivable does not include
$4 million
of contracts assets related to firm service transportation contracts with tiered rates, which are reflected in Other Assets.
|
|
|
(2)
|
Total Accounts Receivable includes Accounts receivables, net of allowance for doubtful accounts and Accounts receivable—affiliated companies.
|
Contract Liabilities
Our contract liabilities primarily consist of prepayments received from customers for which the good or service has not yet been provided in connection with the prepayment. The table below summarizes the change in the contract liabilities for the
three months ended March 31, 2019
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31,
2019
|
|
December 31,
2018
|
|
Amounts recognized in revenues
|
|
|
|
|
|
|
|
(In millions)
|
Deferred revenues
|
$
|
48
|
|
|
$
|
48
|
|
|
$
|
20
|
|
The table below summarizes the timing of recognition of these contract liabilities as of
March 31, 2019
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023 and After
|
|
(In millions)
|
Deferred revenues
|
$
|
22
|
|
|
$
|
6
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
10
|
|
Remaining Performance Obligations
Our remaining performance obligations consist primarily of firm arrangements and minimum volume commitment arrangements. Upon completion of the performance obligations associated with these arrangements, customers are invoiced and revenue is recognized as Service revenues in the Consolidated Statements of Income. The table below summarizes the timing of recognition of the remaining performance obligations as of
March 31, 2019
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023 and After
|
|
(In millions)
|
Transportation and Storage
|
$
|
344
|
|
|
$
|
356
|
|
|
$
|
200
|
|
|
$
|
156
|
|
|
$
|
774
|
|
Gathering and Processing
|
220
|
|
|
164
|
|
|
136
|
|
|
138
|
|
|
461
|
|
Total remaining performance obligations
|
$
|
564
|
|
|
$
|
520
|
|
|
$
|
336
|
|
|
$
|
294
|
|
|
$
|
1,235
|
|
(4) Leases
On January 1, 2019, the Partnership adopted ASU 2016-02, “Leases (ASC 842).” This standard requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Partnership has applied the standard to only contracts that were not expired as of January 1, 2019.
The Partnership elected the optional transition practical expedient to not evaluate land easements that exist or expire before the Partnership's adoption of ASC 842 and that were not previously accounted for as leases under ASC 840. The Partnership elected the optional transition practical expedient to not reassess whether any expired or existing contracts are or contain leases, the lease classification for any expired or existing leases and initial direct costs for any existing leases. Upon adoption, we increased our asset and liability balances on the Condensed Consolidated Balance Sheets by approximately
$35 million
due to the required recognition of right-of-use assets and corresponding lease liabilities for all lease obligations that were classified as operating leases. The Partnership did not recognize a material cumulative adjustment to the Condensed Consolidated Statement of Partners’ Equity and we did not have any material changes in the timing of expense recognition or our accounting policies.
Our lease obligations are primarily comprised of rentals of field equipment and buildings, which are recorded as Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income. Other than the contractual terms for each lease obligation, the key inputs for our calculations of the initial right-of-use assets and corresponding lease liabilities are the expected remaining life and applicable discount rate. Field equipment has an expected lease term of
three
to
five
years, with contractual base terms of
one
to
three
years followed by month-to-month renewals. Field equipment rental arrangements do not generally contain any significant variable lease payments. While certain arrangements may include lower standby rates, field equipment is generally anticipated to be in use for all of its expected lease term. Buildings have an expected lease term of
seven
to
ten
years, which is currently the same as the contractual base term. Building rental arrangements contain market-based renewal options of up to
15
years. Variable lease payments for buildings are generally comprised of costs for utilities, maintenance and building management services. There are no variable lease payments due under building rental arrangements until July 1, 2019, after which amounts will be due monthly. The Partnership is generally not aware of the implicit rate for either field equipment or building rental arrangements, so discount rates are based upon the expected term of each arrangement and the Partnership’s uncollateralized borrowing rate associated with the expected term at the time of lease inception. As of
March 31, 2019
, the weighted average remaining lease term is
4.2 years
and the weighted average discount rate is
5.55%
.
As of
March 31, 2019
, we have right-of-use assets of
$33 million
recorded as Other Assets,
$8 million
of corresponding obligations recorded as Other Current Liabilities and
$26 million
of corresponding obligations recorded as Other Liabilities on the Partnership’s Condensed Consolidated Balance Sheet. All lease obligations outstanding during the
three months ended March 31, 2019
were classified as operating leases, therefore all cash flows are reflected in Cash Flows from Operating Activities. During the
three months ended March 31, 2019
, rental costs associated with field equipment and buildings were
$7 million
and
$2 million
, respectively.
The table below summarizes lease expense for the three-month period ended March 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2019
|
|
Gathering and
Processing
|
|
Transportation
and Storage
|
|
Total
|
|
|
|
|
|
|
|
(In millions)
|
Lease Expense:
|
|
|
|
|
|
Lease Cost:
|
|
|
|
|
|
Operating lease cost
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
2
|
|
Short-term lease cost
|
6
|
|
|
1
|
|
|
7
|
|
Total Lease Cost
|
$
|
8
|
|
|
$
|
1
|
|
|
$
|
9
|
|
Under ASC 842, as of
March 31, 2019
, the Partnership has operating lease obligations expiring at various dates. The
$17 million
difference between undiscounted cash flows for operating leases and our
$35 million
of lease obligations is due to the impact of the applicable discount rate. Undiscounted cash flows for operating lease liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024 and After
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Noncancellable operating leases
|
$
|
11
|
|
|
$
|
11
|
|
|
$
|
6
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
14
|
|
|
$
|
52
|
|
Under ASC 840, as of
December 31, 2018
, the Partnership had the following operating lease obligations as well as the
estimate of the period in which the obligation will be settled:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2019
|
|
2020-2021
|
|
2022-2023
|
|
After 2023
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Noncancellable operating leases
|
$
|
14
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
$
|
14
|
|
|
$
|
40
|
|
(5)
Acquisition
Velocity Holdings, LLC Acquisition
On November 1, 2018, the Partnership acquired all of the equity interests in Velocity Holdings, LLC, now EOCS, which owns and operates a crude oil and condensate gathering system in the SCOOP and STACK plays of the Anadarko Basin, for approximately
$444 million
in cash, subject to certain customary working capital adjustments. The acquisition was accounted for as a business combination and was funded with borrowings under the commercial paper program. During the fourth quarter of 2018, the Partnership finalized the purchase price allocation as of November 1, 2018.
The following table presents the fair value of the identified assets acquired and liabilities assumed at the acquisition date:
|
|
|
|
|
Purchase price allocation:
|
|
Assets acquired:
|
|
Cash
|
$
|
1
|
|
Current Assets
|
3
|
|
Property, plant and equipment
|
124
|
|
Intangibles
|
259
|
|
Goodwill
|
86
|
|
Liabilities assumed:
|
|
Current liabilities
|
1
|
|
Less: Non-Controlling Interest at fair value
|
28
|
|
Total identifiable net assets
|
$
|
444
|
|
The Partnership recognized intangible assets related to customer relationships. The acquired intangible assets will be amortized on a straight-line basis over the estimated customer contract life of approximately
15
years. Goodwill recognized from the acquisition primarily relates to greater operating leverage in the Anadarko Basin and is allocated to the gathering and processing segment. Included within the acquisition was
60%
of a
26
-mile pipeline system joint venture with a third party which owns and operates a refinery connected to the EOCS system. This joint venture’s financials have been consolidated within the Partnership’s financial statements resulting in
$28 million
in non-controlling interest. The Partnership incurred approximately
$6 million
of acquisition costs associated with this transaction, which were included in General and administrative expense in the Consolidated Statements of Income for the
twelve months ended December 31, 2018
. The Partnership determined not to include pro forma consolidated financial statements for the periods presented as the impact would not be material.
(6) Earnings Per Limited Partner Unit
The following table illustrates the Partnership’s calculation of earnings per unit for common units:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions, except per unit data)
|
Net income
|
$
|
123
|
|
|
$
|
114
|
|
Net income attributable to noncontrolling interest
|
1
|
|
|
—
|
|
Series A Preferred Unit distributions
|
9
|
|
|
9
|
|
General partner interest in net income
|
—
|
|
|
—
|
|
Net income available to common unitholders
|
$
|
113
|
|
|
$
|
105
|
|
|
|
|
|
Net income allocable to common units
|
$
|
113
|
|
|
$
|
105
|
|
Dilutive effect of Series A Preferred Unit distributions
|
—
|
|
|
—
|
|
Diluted net income allocable to common units
|
113
|
|
|
105
|
|
|
|
|
|
Basic earnings per unit
|
|
|
|
Common units
|
$
|
0.26
|
|
|
$
|
0.24
|
|
|
|
|
|
Basic weighted average number of common units outstanding
(1)
|
435
|
|
|
434
|
|
Dilutive effect of Series A Preferred Units
|
—
|
|
|
—
|
|
Dilutive effect of performance units
|
—
|
|
|
1
|
|
Diluted weighted average number of common units outstanding
|
435
|
|
|
435
|
|
|
|
|
|
Diluted earnings per unit
|
|
|
|
Common units
|
$
|
0.26
|
|
|
$
|
0.24
|
|
____________________
|
|
(1)
|
Basic weighted average number of outstanding common units includes approximately
one million
time-based phantom units for each of the
three months ended March 31, 2019
and
2018
, respectively.
|
(7) Partners’ Equity
The Partnership Agreement requires that, within
60
days after the end of each quarter, the Partnership distribute all of its available cash (as defined in the Partnership Agreement) to unitholders of record on the applicable record date.
The Partnership paid or has authorized payment of the following cash distributions to common unitholders, as applicable, during
2018
and
2019
(in millions, except for per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Record Date
|
|
Payment Date
|
|
Per Unit Distribution
|
|
Total Cash Distribution
|
March 31, 2019
(1)
|
|
May 21, 2019
|
|
May 29, 2019
|
|
$
|
0.318
|
|
|
$
|
138
|
|
December 31, 2018
|
|
February 19, 2019
|
|
February 26, 2019
|
|
0.318
|
|
|
138
|
|
September 30, 2018
|
|
November 16, 2018
|
|
November 29, 2018
|
|
0.318
|
|
|
138
|
|
June 30, 2018
|
|
August 21, 2018
|
|
August 28, 2018
|
|
0.318
|
|
|
138
|
|
March 31, 2018
|
|
May 22, 2018
|
|
May 29, 2018
|
|
0.318
|
|
|
138
|
|
_____________________
|
|
(1)
|
The Board of Directors declared this
$0.318
per common unit cash distribution on
April 29, 2019
, to be paid on
May 29, 2019
, to common unitholders of record at the close of business on
May 21, 2019
.
|
The Partnership paid or has authorized payment of the following cash distributions to holders of the Series A Preferred Units during
2018
and
2019
(in millions, except for per unit amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Record Date
|
|
Payment Date
|
|
Per Unit Distribution
|
|
Total Cash Distribution
|
March 31, 2019
(1)
|
|
April 29, 2019
|
|
May 15, 2019
|
|
$
|
0.625
|
|
|
$
|
9
|
|
December 31, 2018
|
|
February 8, 2019
|
|
February 14, 2019
|
|
0.625
|
|
|
9
|
|
September 30, 2018
|
|
November 6, 2018
|
|
November 14, 2018
|
|
0.625
|
|
|
9
|
|
June 30, 2018
|
|
August 1, 2018
|
|
August 14, 2018
|
|
0.625
|
|
|
9
|
|
March 31, 2018
|
|
May 1, 2018
|
|
May 15, 2018
|
|
0.625
|
|
|
9
|
|
_____________________
|
|
(1)
|
The Board of Directors declared a
$0.625
per Series A Preferred Unit cash distribution on
April 29, 2019
, to be paid on
May 15, 2019
, to Series A Preferred unitholders of record at the close of business on
April 29, 2019
.
|
ATM Program
On May 12, 2017, the Partnership entered into an ATM Equity Offering Sales Agreement, pursuant to which the Partnership may issue and sell common units having an aggregate offering price of up to
$200 million
, by sales methods and at prices determined by market conditions and other factors at the time of our offerings. The Partnership has no obligation to sell any common units under the ATM Program and the Partnership may suspend sales under the ATM Program at any time. During the
three months ended March 31, 2019
and
March 31, 2018
, the Partnership did not issue common units under the ATM Program. As of
March 31, 2019
,
$197 million
of common units remained available for issuance through the ATM Program.
(8) Investment in Equity Method Affiliate
The Partnership uses the equity method of accounting for investments in entities in which it has an ownership interest between
20%
and
50%
and exercises significant influence.
SESH is owned
50%
by Enbridge, Inc. and
50%
by the Partnership. Pursuant to the terms of the SESH LLC Agreement, if, at any time, CenterPoint Energy has a right to receive less than
50%
of our distributions through its interest in the Partnership and its economic interest in Enable GP, or does not have the ability to exercise certain control rights, Enbridge, Inc. may, under certain circumstances, have the right to purchase the Partnership’s interest in SESH at fair market value, subject to certain exceptions.
The Partnership shares operations of SESH with Enbridge, Inc. under service agreements. The Partnership is responsible for the field operations of SESH. SESH reimburses each party for actual costs incurred, which are billed based upon a combination of direct charges and allocations. The Partnership billed SESH
$3 million
and
$2 million
during the
three months ended March 31, 2019
and
2018
, respectively, associated with these service agreements.
The Partnership includes equity in earnings of equity method affiliate under the Other Income (Expense) caption in the Condensed Consolidated Statements of Income for the
three months ended March 31, 2019
and
2018
.
SESH:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions)
|
Equity in Earnings of Equity Method Affiliate
|
$
|
3
|
|
|
$
|
6
|
|
Distributions from Equity Method Affiliate
(1)
|
$
|
12
|
|
|
$
|
13
|
|
___________________
|
|
(1)
|
Distributions from equity method affiliate includes a
$3 million
and
$6 million
return on investment and a
$9 million
and
$7 million
return of investment for the
three months ended March 31, 2019
and
2018
, respectively.
|
Summarized financial information of SESH:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions)
|
Income Statements:
|
|
|
|
Revenues
|
$
|
27
|
|
|
$
|
28
|
|
Operating income
|
$
|
11
|
|
|
$
|
17
|
|
Net income
|
$
|
7
|
|
|
$
|
12
|
|
(9) Debt
The following table presents the Partnership’s outstanding debt as of
March 31, 2019
and
December 31, 2018
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2019
|
|
December 31, 2018
|
|
Outstanding Principal
|
|
Premium (Discount)
|
|
Total Debt
|
|
Outstanding Principal
|
|
Premium (Discount)
|
|
Total Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Commercial Paper
|
$
|
796
|
|
|
$
|
—
|
|
|
$
|
796
|
|
|
$
|
649
|
|
|
$
|
—
|
|
|
$
|
649
|
|
Revolving Credit Facility
|
—
|
|
|
—
|
|
|
—
|
|
|
250
|
|
|
—
|
|
|
250
|
|
2019 Term Loan Agreement
|
200
|
|
|
—
|
|
|
200
|
|
|
—
|
|
|
—
|
|
|
—
|
|
2019 Notes
|
500
|
|
|
—
|
|
|
500
|
|
|
500
|
|
|
—
|
|
|
500
|
|
2024 Notes
|
600
|
|
|
—
|
|
|
600
|
|
|
600
|
|
|
—
|
|
|
600
|
|
2027 Notes
|
700
|
|
|
(2
|
)
|
|
698
|
|
|
700
|
|
|
(2
|
)
|
|
698
|
|
2028 Notes
|
800
|
|
|
(6
|
)
|
|
794
|
|
|
800
|
|
|
(6
|
)
|
|
794
|
|
2044 Notes
|
550
|
|
|
—
|
|
|
550
|
|
|
550
|
|
|
—
|
|
|
550
|
|
EOIT Senior Notes
|
250
|
|
|
6
|
|
|
256
|
|
|
250
|
|
|
7
|
|
|
257
|
|
Total debt
|
$
|
4,396
|
|
|
$
|
(2
|
)
|
|
$
|
4,394
|
|
|
$
|
4,299
|
|
|
$
|
(1
|
)
|
|
$
|
4,298
|
|
Less: Short-term debt
(1)
|
|
|
|
|
796
|
|
|
|
|
|
|
649
|
|
Less: Current portion of long-term debt
(2)
|
|
|
|
|
756
|
|
|
|
|
|
|
500
|
|
Less: Unamortized debt expense
(3)
|
|
|
|
|
20
|
|
|
|
|
|
|
20
|
|
Total long-term debt
|
|
|
|
|
$
|
2,822
|
|
|
|
|
|
|
$
|
3,129
|
|
____________________
|
|
(1)
|
Short-term debt includes
$796 million
and
$649 million
of outstanding commercial paper as of
March 31, 2019
and
December 31, 2018
, respectively.
|
|
|
(2)
|
As of
March 31, 2019
, Current portion of long-term debt includes
$756 million
outstanding balances of the 2019 Notes due May 15, 2019 and EOIT Senior Notes due March 15, 2020. As of
December 31, 2018
, Current portion of long-term debt includes
$500 million
outstanding balance of the 2019 Notes due May 15, 2019.
|
|
|
(3)
|
As of
March 31, 2019
and
December 31, 2018
, there was an additional
$5 million
and
$6 million
, respectively, of unamortized debt expense related to the Revolving Credit Facility included in Other assets, not included above.
|
Commercial Paper
The Partnership has a commercial paper program, pursuant to which the Partnership is authorized to issue up to
$1.4 billion
of commercial paper. The commercial paper program is supported by our Revolving Credit Facility, and outstanding commercial paper effectively reduces our borrowing capacity thereunder. There were
$796 million
and
$649 million
outstanding under our commercial paper program at
March 31, 2019
and
December 31, 2018
, respectively.
The weighted average interest rate for the outstanding commercial paper was
3.41%
as of
March 31, 2019
.
Revolving Credit Facility
On April 6, 2018, the Partnership amended and restated its Revolving Credit Facility. As amended and restated, the Revolving Credit Facility is a
$1.75 billion
,
5
-year senior unsecured revolving credit facility, which under certain circumstances may be increased from time to time up to an additional
$875 million
, in aggregate. The Revolving Credit Facility is scheduled to mature on April 6, 2023, subject to an extension option, which could be exercised
two
times to extend the term of the Revolving Credit Facility, in each case, for an additional
one
-year term. As of
March 31, 2019
, there were
no
principal advances and
$3 million
in letters of credit outstanding under the Restated Revolving Credit Facility.
The Revolving Credit Facility provides that outstanding borrowings bear interest at the LIBOR and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s applicable credit ratings. As of
March 31, 2019
, the applicable margin for LIBOR-based borrowings under the Revolving Credit Facility was
1.50%
based on the Partnership’s credit ratings. In addition, the Revolving Credit Facility requires the Partnership to pay a fee on unused commitments. The commitment fee is based on the Partnership’s applicable credit rating from the rating agencies. As of
March 31, 2019
, the commitment fee under the restated Revolving Credit Facility was
0.20%
per annum based on the Partnership’s credit ratings. The commitment fee is recorded as interest expense in the Partnership’s Condensed Consolidated Statements of Income.
2019 Term Loan Agreement
On January 29, 2019, the Partnership entered into an unsecured term loan agreement, providing for up to
$1 billion
in advances with Bank of America, N.A., as administrative agent, and the several lenders thereto. The 2019 Term Loan Agreement has a scheduled maturity date of January 29, 2022, but contains an option, which may be exercised up to two times, to extend the maturity date for an additional one-year term. As of
March 31, 2019
, there is a principal advance of
$200 million
outstanding under the 2019 Term Loan Agreement, and a delayed-draw feature permits the Partnership to borrow up to an additional
$800 million
within 180 days of the closing date, subject to the terms and conditions of the 2019 Term Loan Agreement. The 2019 Term Loan Agreement provides that outstanding borrowings bear interest at the eurodollar rate and/or an alternate base rate, at the Partnership’s election, plus an applicable margin. The applicable margin is based on the Partnership’s designated ratings from Standard & Poor’s Rating Services, Moody’s Investor Services and Fitch Ratings. The applicable margin shall equal, (1) in the case of interest rates determined by reference to the eurodollar rate, between
0.75%
and
1.50%
per annum and (2) in the case of interest rates determined by reference to the alternate base rate, between
0%
and
0.50%
per annum. As of
March 31, 2019
, the applicable margin for LIBOR-based advances under the 2019 Term Loan Facility was
1.25%
based on the Partnership’s credit ratings. As of
March 31, 2019
, the weighted average interest rate of the 2019 Term Loan Agreement was
3.74%
.
The 2019 Term Loan Agreement requires the Partnership to, starting April 29, 2019 and continuing until the date on which all commitments have expired or been terminated or the amount available to be drawn is zero, pay a ticking fee on each lender’s unused commitment amount. The ticking fee shall equal a per annum rate of
0.125%
on the actual daily amount of such lender’s portion of the unused commitments.
Advances under the 2019 Term Loan Agreement are subject to certain conditions precedent, including the accuracy in all material respects of certain representations and warranties and the absence of any default or event of default. Advances under the 2019 Term Loan Agreement may be used to refinance indebtedness outstanding from time to time and for other general corporate purposes, including to fund acquisitions, investments and capital expenditures. Advances under the 2019 Term Loan Agreement can be prepaid, in whole or in part, at any time without premium or penalty, other than usual and customary LIBOR breakage costs, if applicable.
The 2019 Term Loan Agreement contains a financial covenant requiring the Partnership to maintain a ratio of consolidated funded debt to consolidated EBITDA as of the last day of each fiscal quarter of less than or equal to
5.00
to 1.00; provided that, for a certain period time following an acquisition by the Partnership or certain of its subsidiaries with a purchase price that when combined with the aggregate purchase price for all other such acquisitions in any rolling 12-month period, is equal to or greater than
$25 million
, the consolidated funded debt to consolidated EBITDA ratio as of the last day of each such fiscal quarter during such period would be permitted to be up to
5.50
to 1.00.
The 2019 Term Loan Agreement also contains covenants that restrict the Partnership and certain of its subsidiaries in respect of, among other things, mergers and consolidations, sales of all or substantially all assets, incurrence of subsidiary indebtedness, incurrence of liens, transactions with affiliates, designation of subsidiaries as Excluded Subsidiaries (as defined in the 2019 Term Loan Agreement), restricted payments, changes in the nature of their respective business and entering into certain restrictive agreements. The 2019 Term Loan Agreement is subject to acceleration upon the occurrence of certain defaults, including, among others, payment defaults on such facility, breach of representations, warranties and covenants, acceleration of indebtedness ( other
than intercompany and non-recourse indebtedness) of
$100 million
or more in the aggregate, change of control, nonpayment of uninsured judgments in excess of
$100 million
, and the occurrence of certain ERISA and bankruptcy events, subject where applicable to specified cure periods.
Senior Notes
As of
March 31, 2019
, the Partnership’s debt included the 2019 Notes, 2024 Notes, 2027 Notes, 2028 Notes and 2044 Notes, which had
$8 million
of unamortized discount and
$20 million
of unamortized debt expense at
March 31, 2019
, resulting in effective interest rates of
2.56%
,
4.01%
,
4.57%
,
5.20%
and
5.08%
, respectively, during the
three
months ended
March 31, 2019
.
As of
March 31, 2019
, the Partnership’s debt included EOIT’s Senior Notes. The EOIT Senior Notes had
$6 million
of unamortized premium at
March 31, 2019
, resulting in an effective interest rate of
3.80%
during the
three
months ended
March 31, 2019
.
As of
March 31, 2019
, the Partnership and EOIT were in compliance with all of their debt agreements, including financial covenants.
(10) Derivative Instruments and Hedging Activities
The Partnership is exposed to certain risks relating to its ongoing business operations. The primary risk managed using derivative instruments is commodity price risk. The Partnership is also exposed to credit risk in its business operations.
Commodity Price Risk
The Partnership has used forward physical contracts, commodity price swap contracts and commodity price option features to manage the Partnership’s commodity price risk exposures in the past. Commodity derivative instruments used by the Partnership are as follows:
|
|
•
|
NGL put options, NGL futures and swaps, and WTI crude oil futures, swaps and swaptions are used to manage the Partnership’s NGL and condensate exposure associated with its processing agreements;
|
|
|
•
|
natural gas futures and swaps, natural gas options, natural gas swaptions and natural gas commodity purchases and sales are used to manage the Partnership’s natural gas exposure associated with its gathering, processing, transportation and storage assets, contracts and asset management activities.
|
Normal purchases and normal sales contracts are not recorded in Other Assets or Liabilities in the Condensed Consolidated Balance Sheets and earnings are recognized and recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales treatment to: (i) commodity contracts for the purchase and sale of natural gas used in or produced by the Partnership’s operations and (ii) commodity contracts for the purchase and sale of NGLs produced by the Partnership’s gathering and processing business.
The Partnership recognizes its non-exchange traded derivative instruments as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value with such amounts classified as current or long-term based on their anticipated settlement. Exchange traded transactions are settled on a net basis daily through margin accounts with a clearing broker and are recorded as Other Assets or Liabilities in the Condensed Consolidated Balance Sheets at fair value on a net basis with such amounts classified as current or long-term based on their anticipated settlement.
As of
March 31, 2019
and
December 31, 2018
, the Partnership had
no
derivative instruments that were designated as cash flow or fair value hedges for accounting purposes.
Credit Risk
Credit risk includes the risk that counterparties that owe the Partnership money or energy will breach their obligations. If the counterparties to these arrangements fail to perform, the Partnership may seek or be forced to enter into alternative arrangements. In that event, the Partnership’s financial results could be adversely affected, and the Partnership could incur losses.
Derivatives Not Designated as Hedging Instruments
Derivative instruments not designated as hedging instruments for accounting purposes are utilized in the Partnership’s asset management activities. For derivative instruments not designated as hedging instruments, the gain or loss on the derivative is recognized currently in earnings.
Quantitative Disclosures Related to Derivative Instruments
The majority of natural gas physical purchases and sales not designated as hedges for accounting purposes are priced based on a monthly or daily index, and the fair value is subject to little or no market price risk. Natural gas physical sales volumes exceed natural gas physical purchase volumes due to the marketing of natural gas volumes purchased via the Partnership’s processing contracts, which are not derivative instruments.
As of
March 31, 2019
and
December 31, 2018
, the Partnership had the following derivative instruments that were not designated as hedging instruments for accounting purposes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2019
|
|
December 31, 2018
|
|
Gross Notional Volume
|
|
Purchases
|
|
Sales
|
|
Purchases
|
|
Sales
|
Natural gas—
TBtu
(1)
|
|
|
|
|
|
|
|
Financial fixed futures/swaps
|
15
|
|
|
29
|
|
|
16
|
|
|
28
|
|
Financial basis futures/swaps
|
17
|
|
|
45
|
|
|
18
|
|
|
29
|
|
Financial swaptions
(3)
|
—
|
|
|
3
|
|
|
—
|
|
|
1
|
|
Physical purchases/sales
|
—
|
|
|
10
|
|
|
—
|
|
|
11
|
|
Crude oil (for condensate)—
MBbl
(2)
|
|
|
|
|
|
|
|
Financial futures/swaps
|
—
|
|
|
735
|
|
|
—
|
|
|
945
|
|
Financial swaptions
(3)
|
—
|
|
|
30
|
|
|
—
|
|
|
30
|
|
Natural gas liquids—
MBbl
(4)
|
|
|
|
|
|
|
|
Financial futures/swaps
|
1,465
|
|
|
2,940
|
|
|
270
|
|
|
2,535
|
|
____________________
|
|
(1)
|
As of
March 31, 2019
,
78.3%
of the natural gas contracts had durations of one year or less,
20.2%
had durations of more than one year and less than two years and
1.5%
had durations of more than two years. As of
December 31, 2018
,
74.0%
of the natural gas contracts had durations of one year or less,
24.2%
had durations of more than one year and less than two years and
1.8%
had durations of more than two years.
|
|
|
(2)
|
As of
March 31, 2019
,
86.3%
of the crude oil (for condensate) contracts had durations of one year or less and
13.7%
had durations of more than one year and less than two years. As of
December 31, 2018
,
76.9%
of the crude oil (for condensate) contracts had durations of one year or less and
23.1%
had durations of more than one year and less than two years.
|
|
|
(3)
|
The notional contains a combined derivative instrument consisting of a fixed price swap and a sold option, which gives the counterparties the right, but not the obligation, to increase the notional quantity hedged under the fixed price swap until the option expiration date. The notional volume represents the volume prior to option exercise.
|
|
|
(4)
|
As of
March 31, 2019
,
94.9%
of the natural gas liquids contracts had durations of one year or less and
5.1%
had durations of more than one year and less than two years. As of
December 31, 2018
,
86.1%
of the natural gas liquid contracts had durations of one year or less and
13.9%
had durations of more than one year and less than two years.
|
Balance Sheet Presentation Related to Derivative Instruments
The fair value of the derivative instruments that are presented in the Partnership’s Condensed Consolidated Balance Sheets as of
March 31, 2019
and
December 31, 2018
that were not designated as hedging instruments for accounting purposes are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2019
|
|
December 31, 2018
|
|
|
|
Fair Value
|
Instrument
|
Balance Sheet Location
|
|
Assets
|
|
Liabilities
|
|
Assets
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Natural gas
|
|
|
|
|
|
|
|
Financial futures/swaps
|
Other Current
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
3
|
|
|
$
|
5
|
|
Financial futures/swaps
|
Other
|
|
—
|
|
|
2
|
|
|
—
|
|
|
2
|
|
Physical purchases/sales
|
Other Current
|
|
2
|
|
|
—
|
|
|
3
|
|
|
—
|
|
Physical purchases/sales
|
Other
|
|
2
|
|
|
—
|
|
|
4
|
|
|
—
|
|
Crude oil (for condensate)
|
|
|
|
|
|
|
|
|
|
Financial futures/swaps
|
Other Current
|
|
—
|
|
|
4
|
|
|
9
|
|
|
3
|
|
Financial futures/swaps
|
Other
|
|
1
|
|
|
—
|
|
|
2
|
|
|
—
|
|
Natural gas liquids
|
|
|
|
|
|
|
|
|
|
Financial futures/swaps
|
Other Current
|
|
10
|
|
|
—
|
|
|
10
|
|
|
1
|
|
Financial futures/swaps
|
Other
|
|
1
|
|
|
—
|
|
|
2
|
|
|
—
|
|
Total gross derivatives
(1)
|
|
|
$
|
17
|
|
|
$
|
7
|
|
|
$
|
33
|
|
|
$
|
11
|
|
_____________________
|
|
(1)
|
See Note 11 for a reconciliation of the Partnership’s total derivatives fair value to the Partnership’s Condensed Consolidated Balance Sheets as of
March 31, 2019
and
December 31, 2018
.
|
Income Statement Presentation Related to Derivative Instruments
The following table presents the effect of derivative instruments on the Partnership’s Condensed Consolidated Statements of Income for the
three
months ended
March 31, 2019
and
2018
:
|
|
|
|
|
|
|
|
|
|
Amounts Recognized in Income
|
|
Three Months Ended March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions)
|
Natural gas
|
|
|
|
Financial futures/swaps (losses) gains
|
$
|
(1
|
)
|
|
$
|
(3
|
)
|
Physical purchases/sales gains
|
(1
|
)
|
|
2
|
|
Crude oil (for condensate)
|
|
|
|
Financial futures/swaps (losses) gains
|
(11
|
)
|
|
(3
|
)
|
Financial swaptions (losses) gains
|
—
|
|
|
—
|
|
Natural gas liquids
|
|
|
|
Financial futures/swaps (losses) gains
|
3
|
|
|
4
|
|
Total
|
$
|
(10
|
)
|
|
$
|
—
|
|
For derivatives not designated as hedges in the tables above, amounts recognized in income for the periods ended
March 31, 2019
and
2018
, if any, are reported in Product sales.
The following table presents the components of gain (loss) on derivative activity in the Partnership’s Condensed Consolidated Statements of Income for the
three
months ended
March 31, 2019
and
2018
:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions)
|
Change in fair value of derivatives
|
$
|
(12
|
)
|
|
$
|
(2
|
)
|
Realized gain (loss) on derivatives
|
2
|
|
|
2
|
|
Gain (loss) on derivative activity
|
$
|
(10
|
)
|
|
$
|
—
|
|
Credit-Risk Related Contingent Features in Derivative Instruments
In the event Moody’s Investors Services or Standard & Poor’s Ratings Services were to lower the Partnership’s senior unsecured debt rating to a below investment grade rating, the Partnership could be required to provide additional credit assurances to third parties, which could include letters of credit or cash collateral to satisfy its obligation under its financial and physical contracts relating to derivative instruments that are in a net liability position. As of
March 31, 2019
, under these obligations, the Partnership has posted
no
cash collateral related to NGL swaps and crude swaps and swaptions and
no
additional collateral may be required to be posted by the Partnership in the event of a credit ratings downgrade to a below investment grade rating.
(11) Fair Value Measurements
Certain assets and liabilities are recorded at fair value in the Condensed Consolidated Balance Sheets and are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined below and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities are as follows:
Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Instruments classified as Level 1 include natural gas futures, swaps and options transactions for contracts traded on either the NYMEX or the ICE and settled through either a NYMEX or ICE clearing broker.
Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets. Instruments classified as Level 2 generally include over-the-counter natural gas swaps, natural gas swaptions, natural gas basis swaps and natural gas purchase and sales transactions in markets such that the pricing is closely related to the NYMEX or the ICE pricing, and over-the-counter WTI crude oil swaps and swaptions for condensate sales.
Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Unobservable inputs reflect the Partnership’s judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The Partnership develops these inputs based on the best information available, including the Partnership’s own data.
The Partnership utilizes the market approach in determining the fair value of its derivative positions by using either NYMEX, ICE or WTI published market prices, independent broker pricing data or broker/dealer valuations. The valuations of derivatives with pricing based on NYMEX or ICE published market prices may be considered Level 1 if they are settled through a NYMEX or ICE clearing broker account with daily margining. Over-the-counter derivatives with NYMEX, ICE or WTI based prices are considered Level 2 due to the impact of counterparty credit risk. Valuations based on independent broker pricing or broker/dealer valuations may be classified as Level 2 only to the extent they may be validated by an additional source of independent market data for an identical or closely related active market. Certain derivatives with option features may be classified as Level 2 if valued using an industry standard Black-Scholes option pricing model that contain observable inputs in the marketplace throughout the term of the derivative instrument. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, contracts are valued using internally developed methodologies that consider historical relationships among various quoted prices in active markets that result in management’s best estimate of fair value. These contracts are classified as Level 3. As of
March 31, 2019
, there were no contracts classified as Level 3.
The Partnership determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes transfers between levels at the end of the reporting period. For the
three months ended March 31, 2019
, there were no transfers between levels.
The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material.
Estimated Fair Value of Financial Instruments
The fair values of all accounts receivable, notes receivable, accounts payable, commercial paper and other such financial instruments on the Condensed Consolidated Balance Sheets are estimated to be approximately equivalent to their carrying amounts due to their short-term nature and have been excluded from the table below. The following table summarizes the fair value and carrying amount of the Partnership’s financial instruments as of
March 31, 2019
and
December 31, 2018
.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2019
|
|
December 31, 2018
|
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Debt
|
|
|
|
|
|
|
|
Revolving Credit Facility (Level 2)
(1)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
250
|
|
|
$
|
250
|
|
2019 Term Loan Agreement (Level 2)
|
200
|
|
|
200
|
|
|
—
|
|
|
—
|
|
2019 Notes (Level 2)
|
500
|
|
|
499
|
|
|
500
|
|
|
497
|
|
2024 Notes (Level 2)
|
600
|
|
|
599
|
|
|
600
|
|
|
571
|
|
2027 Notes (Level 2)
|
698
|
|
|
684
|
|
|
698
|
|
|
642
|
|
2028 Notes (Level 2)
|
794
|
|
|
811
|
|
|
794
|
|
|
764
|
|
2044 Notes (Level 2)
|
550
|
|
|
489
|
|
|
550
|
|
|
445
|
|
EOIT Senior Notes (Level 2)
|
256
|
|
|
257
|
|
|
257
|
|
|
256
|
|
____________________
|
|
(1)
|
Borrowing capacity is effectively reduced by our borrowings outstanding under the commercial paper program.
$796 million
and
$649 million
of commercial paper was outstanding as of
March 31, 2019
and
December 31, 2018
, respectively.
|
The fair value of the Partnership’s Revolving Credit Facility, 2019 Term Loan Agreement, 2019 Notes, 2024 Notes, 2027 Notes, 2028 Notes, 2044 Notes and EOIT Senior Notes is based on quoted market prices and estimates of current rates available for similar issues with similar maturities and is classified as Level 2 in the fair value hierarchy.
Non-Financial Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances (e.g., when there is evidence of impairment). As of
March 31, 2019
, no material fair value adjustments or fair value measurements were required for these non-financial assets or liabilities.
Contracts with Master Netting Arrangements
Fair value amounts recognized for forward, interest rate swap, option and other conditional or exchange contracts executed with the same counterparty under a master netting arrangement may be offset. The reporting entity’s choice to offset or not must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts, whether for the same type of conditional or exchange contract or for different types of contracts, with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for forward, interest rate swap, option and other conditional or exchange contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Consolidated Balance Sheets. The Partnership has presented the fair values of its derivative contracts under master netting agreements using a net fair value presentation.
The following tables summarize the Partnership’s assets and liabilities that are measured at fair value on a recurring basis as of
March 31, 2019
and
December 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2019
|
Commodity Contracts
|
|
Gas Imbalances
(1)
|
|
Assets
|
|
Liabilities
|
|
Assets
(2)
|
|
Liabilities
(3)
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Quoted market prices in active market for identical assets (Level 1)
|
$
|
1
|
|
|
$
|
6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Significant other observable inputs (Level 2)
|
16
|
|
|
1
|
|
|
14
|
|
|
6
|
|
Unobservable inputs (Level 3)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total fair value
|
17
|
|
|
7
|
|
|
14
|
|
|
6
|
|
Netting adjustments
|
(6
|
)
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
Total
|
$
|
11
|
|
|
$
|
1
|
|
|
$
|
14
|
|
|
$
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
Commodity Contracts
|
|
Gas Imbalances
(1)
|
|
Assets
|
|
Liabilities
|
|
Assets
(2)
|
|
Liabilities
(3)
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Quoted market prices in active market for identical assets (Level 1)
|
$
|
4
|
|
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Significant other observable inputs (Level 2)
|
29
|
|
|
2
|
|
|
18
|
|
|
17
|
|
Unobservable inputs (Level 3)
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total fair value
|
33
|
|
|
11
|
|
|
18
|
|
|
17
|
|
Netting adjustments
|
(9
|
)
|
|
(9
|
)
|
|
—
|
|
|
—
|
|
Total
|
$
|
24
|
|
|
$
|
2
|
|
|
$
|
18
|
|
|
$
|
17
|
|
______________________
|
|
(1)
|
The Partnership uses the market approach to fair value its gas imbalance assets and liabilities at individual, or where appropriate an average of, current market indices applicable to the Partnership’s operations, not to exceed net realizable value. There were no netting adjustments as of
March 31, 2019
and
December 31, 2018
.
|
|
|
(2)
|
Gas imbalance assets exclude fuel reserves for under retained fuel due from shippers of
$8 million
and
$11 million
at
March 31, 2019
and
December 31, 2018
, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created, and which are not subject to revaluation at fair market value.
|
|
|
(3)
|
Gas imbalance liabilities exclude fuel reserves for over retained fuel due to shippers of
$9 million
and
$5 million
at
March 31, 2019
and
December 31, 2018
, respectively, which fuel reserves are based on the value of natural gas at the time the imbalance was created, and which are not subject to revaluation at fair market value.
|
(12)
Supplemental Disclosure of Cash Flow Information
The following table provides information regarding supplemental cash flow information:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions)
|
Supplemental Disclosure of Cash Flow Information:
|
|
|
|
Cash Payments:
|
|
|
|
Interest, net of capitalized interest
|
$
|
32
|
|
|
$
|
29
|
|
Income taxes, net of refunds
|
—
|
|
|
2
|
|
Non-cash transactions:
|
|
|
|
Accounts payable related to capital expenditures
|
39
|
|
|
50
|
|
Lease liabilities arising from the implementation of ASC 842
|
35
|
|
|
—
|
|
The following table reconciles cash and cash equivalents and restricted cash on the Condensed Consolidated Balance Sheets to cash, cash equivalents and restricted cash on the Condensed Consolidated Statements of Cash Flows:
|
|
|
|
|
|
|
|
|
|
March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions)
|
Cash and cash equivalents
|
$
|
18
|
|
|
$
|
30
|
|
Restricted cash
|
1
|
|
|
14
|
|
Cash, cash equivalents and restricted cash shown in the Condensed Consolidated Statements of Cash Flows
|
$
|
19
|
|
|
$
|
44
|
|
During the
three months ended March 31, 2019
, Restricted cash decreased
$13 million
due to the release of cash collateral which was provided as credit assurance by a third party.
(13) Related Party Transactions
The material related party transactions with CenterPoint Energy, OGE Energy and their respective subsidiaries are summarized below. There were no material related party transactions with other affiliates.
Transportation and Storage Agreements
Transportation and Storage Agreements with CenterPoint Energy
EGT provides natural gas transportation and storage services to CenterPoint Energy’s LDCs in Arkansas, Louisiana, Oklahoma and Northeast Texas under a combination of contracts that include the following types of services: firm transportation, firm transportation with seasonal demand, firm storage, no-notice transportation with storage and maximum rate firm transportation. The contracts for firm transportation with seasonal demand will remain in effect through March 31, 2021. The contracts for firm transportation, firm storage and firm no-notice transportation with storage, as well as the contracts for maximum rate firm transportation for Oklahoma and portions of Northeast Texas, are in effect through March 31, 2021, and will remain in effect thereafter unless and until terminated by either party upon
180
days’ prior written notice. The contracts for maximum firm rate transportation for Arkansas, Louisiana and Texarkana, Texas terminated on March 31, 2018. MRT provides firm transportation and firm storage services to CenterPoint Energy’s LDCs in Arkansas and Louisiana. Contracts for these services are in effect through May 15, 2023 and will remain in effect thereafter unless and until terminated by either party upon twelve months’ prior written notice.
Transportation and Storage Agreement with OGE Energy
EOIT provides no-notice load-following transportation and storage services to OGE Energy. On March 17, 2014, EOIT entered into a transportation agreement with OGE Energy, for four of its generating facilities, with a primary term of May 1, 2014 through April 30, 2019. On October 24, 2018, EOIT entered into a no-notice load-following transportation agreement with OGE Energy, with a primary term of April 1, 2019 through May 1, 2024. Following the primary term, the agreement will remain in effect from year to year thereafter unless either party provides notice of termination to the other party at least
180
days prior to the commencement of the succeeding annual period. On December 6, 2016, EOIT entered into an additional firm transportation agreement with OGE Energy, for one of its generating facilities with a primary term of December 1, 2018 through December 1, 2038.
Gas Sales and Purchases Transactions
The Partnership sells natural gas volumes to affiliates of CenterPoint Energy and OGE Energy or purchases natural gas volumes from affiliates of CenterPoint Energy through a combination of forward, monthly and daily transactions. The Partnership enters into these physical natural gas transactions in the normal course of business based upon relevant market prices.
The Partnership’s revenues from affiliated companies accounted for
6%
and
7%
of total revenues during the
three months ended March 31, 2019
and
2018
, respectively. Amounts of revenues from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions)
|
Gas transportation and storage service revenues — CenterPoint Energy
|
$
|
33
|
|
|
$
|
33
|
|
Natural gas product sales — CenterPoint Energy
|
1
|
|
|
6
|
|
Gas transportation and storage service revenues — OGE Energy
|
13
|
|
|
9
|
|
Natural gas product sales — OGE Energy
|
1
|
|
|
1
|
|
Total revenues — affiliated companies
|
$
|
48
|
|
|
$
|
49
|
|
Amounts of natural gas purchased from affiliated companies included in the Partnership’s Condensed Consolidated Statements of Income are summarized as follows:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions)
|
Cost of natural gas purchases — CenterPoint Energy
|
$
|
—
|
|
|
$
|
2
|
|
Cost of natural gas purchases — OGE Energy
|
6
|
|
|
3
|
|
Total cost of natural gas purchases — affiliated companies
|
$
|
6
|
|
|
$
|
5
|
|
Seconded employees and corporate services
As of
March 31, 2019
, the Partnership had certain employees who are participants under OGE Energy’s defined benefit and retiree medical plans, who will remain seconded to the Partnership, subject to certain termination rights of the Partnership and OGE Energy. The Partnership’s reimbursement of OGE Energy for seconded employee costs arising out of OGE Energy’s defined benefit and retiree medical plans is fixed at actual cost subject to a cap of
$5 million
in 2019 and thereafter, unless and until secondment is terminated.
The Partnership receives services and support functions from each of CenterPoint Energy and OGE Energy under services agreements for an initial term that ended on April 30, 2016. The services agreements automatically extend year-to-year at the end of the initial term, unless terminated by the Partnership with at least
90
days’ notice prior to the end of any extension. Additionally, the Partnership may terminate the services agreements at any time with
180
days’ notice, if approved by the Board of Enable GP. The Partnership reimburses CenterPoint Energy and OGE Energy for these services up to annual caps, which for 2019 are
$1 million
and
$1 million
, respectively.
Amounts charged to the Partnership by affiliates for seconded employees and corporate services, included primarily in Operation and maintenance and General and administrative expenses in the Partnership’s Condensed Consolidated Statements of Income are as follows:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions)
|
Corporate Services — CenterPoint Energy
|
$
|
—
|
|
|
$
|
1
|
|
Seconded Employee Costs — OGE Energy
|
6
|
|
|
8
|
|
Total corporate services and seconded employee costs
|
$
|
6
|
|
|
$
|
9
|
|
(14) Commitments and Contingencies
The Partnership is routinely involved in legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings may from time to time involve substantial amounts. The Partnership regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Partnership does not currently expect the disposition of these matters to have a material adverse effect on its financial condition, results of operations or cash flows.
On January 1, 2017, the Partnership entered into a
10
-year gathering and processing agreement, which became effective on July 1, 2018, with an affiliate of Energy Transfer Partners, LP for
400
MMcf/d of deliveries to the Godley Plant in Johnson County, Texas. As of
March 31, 2019
, the Partnership estimates the remaining associated
10
-year minimum volume commitment fee to be
$209 million
.
On September 13, 2018, the Partnership executed a precedent agreement for the development of the Gulf Run Pipeline, an interstate natural gas transportation project.
On January 30, 2019, a final investment decision was made by Golden Pass LNG, the cornerstone shipper for the LNG facility to be served by the Gulf Run Pipeline project.
Subject to approval of the project by the FERC, the Partnership will be required to construct a large-diameter pipeline from northern Louisiana to Gulf Coast markets. In addition, the Partnership may transfer existing EGT transportation infrastructure to the Gulf Run Pipeline. Under the precedent agreement, the Partnership estimates the cost to complete the Gulf Run Pipeline project would be as much as
$550 million
and the project is backed by a
20
-year firm transportation service. The Gulf Run Pipeline connects natural gas producing regions in the U.S., including the Haynesville, Marcellus, Utica and Barnett shales and the Mid-Continent region. The project is expected to be placed into service in 2022.
(15) Equity-Based Compensation
The following table summarizes the Partnership’s equity-based compensation expense for the
three
months ended
March 31, 2019
and
2018
related to performance units, restricted units and phantom units for the Partnership’s employees and independent directors:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2019
|
|
2018
|
|
|
|
|
|
(In millions)
|
Performance units
|
$
|
3
|
|
|
$
|
3
|
|
Restricted units
|
—
|
|
|
1
|
|
Phantom units
|
1
|
|
|
1
|
|
Total compensation expense
|
$
|
4
|
|
|
$
|
5
|
|
The following table presents the assumptions related to the performance share units granted in 2019.
|
|
|
|
|
2019
|
Number of units granted
|
610,170
|
|
Fair value of units granted
|
19.95
|
|
Expected distribution yield
|
8.38
|
%
|
Expected price volatility
|
34.2
|
%
|
Risk-free interest rate
|
2.54
|
%
|
Expected life of units (in years)
|
3
|
|
The following table presents the number of phantom units granted and the grant date fair value related to the phantom units granted in 2019.
|
|
|
|
|
2019
|
Phantom Units granted
|
574,121
|
|
Fair value of phantom units granted
|
$14.57 - $15.04
|
Units Outstanding
A summary of the activity for the Partnership’s performance units and phantom units applicable to the Partnership’s employees at
March 31, 2019
and changes during the first quarter of
2019
are shown in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance Units
|
|
Phantom Units
|
|
Number
of Units
|
|
Weighted Average Grant-Date Fair Value, Per Unit
|
|
Number
of Units
|
|
Weighted Average Grant-Date Fair Value, Per Unit
|
|
|
|
|
|
|
|
|
|
(In millions, except unit data)
|
Units outstanding at December 31, 2018
|
2,109,835
|
|
|
$
|
14.33
|
|
|
1,447,590
|
|
|
$
|
12.38
|
|
Granted
(1)
|
610,170
|
|
|
19.95
|
|
|
574,121
|
|
|
15.04
|
|
Vested
(2)
|
(1,113,159
|
)
|
|
10.45
|
|
|
(547,354
|
)
|
|
8.16
|
|
Forfeited
|
(26,474
|
)
|
|
18.22
|
|
|
(20,646
|
)
|
|
14.46
|
|
Units outstanding at March 31, 2019
|
1,580,372
|
|
|
$
|
19.17
|
|
|
1,453,711
|
|
|
$
|
14.98
|
|
Aggregate intrinsic value of units outstanding at March 31, 2019
|
$
|
22
|
|
|
|
|
$
|
21
|
|
|
|
_____________________
|
|
(1)
|
Performance units represents the target number of performance units granted. The actual number of performance units earned, if any, is dependent upon performance and may range from
zero
percent to
200
percent of the target.
|
|
|
(2)
|
Performance units vested as of
March 31, 2019
include
1,097,846
units from the 2016 annual grant, which were approved by the Board of Directors in 2016 and paid out at
200%
, or
2,195,692
units on March 1, 2019, based on the level of achievement of a performance goal established by the Board of Directors over the performance period of January 1, 2016 through
December 31, 2018
.
|
Unrecognized Compensation Cost
A summary of the Partnership’s unrecognized compensation cost for its non-vested performance units and phantom units, and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.
|
|
|
|
|
|
|
|
March 31, 2019
|
|
Unrecognized Compensation Cost
(In millions)
|
|
Weighted Average Period for Recognition
(In years)
|
Performance Units
|
$
|
20
|
|
|
2.00
|
Phantom Units
|
15
|
|
|
2.02
|
Total
|
$
|
35
|
|
|
|
As of
March 31, 2019
, there were
6,235,141
units available for issuance under the long-term incentive plan.
(16) Reportable Segments
The Partnership’s determination of reportable segments considers the strategic operating units under which it manages sales, allocates resources and assesses performance of various products and services to customers in differing regulatory environments. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies excerpt in the Partnership’s audited
2018
consolidated financial statements included in the Annual Report. The Partnership uses operating income as the measure of profit or loss for its reportable segments.
The Partnership’s assets and operations are organized into
two
reportable segments: (i) gathering and processing, which primarily provides natural gas and crude oil gathering and natural gas processing services to our producer customers, and (ii) transportation and storage, which provides interstate and intrastate natural gas pipeline transportation and storage service primarily to our producer, power plant, LDC and industrial end-user customers.
Financial data for reportable segments are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2019
|
Gathering and
Processing
|
|
Transportation
(1)
and Storage
|
|
Eliminations
|
|
Total
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Product sales
|
$
|
423
|
|
|
$
|
167
|
|
|
$
|
(147
|
)
|
|
$
|
443
|
|
Service revenues
|
207
|
|
|
149
|
|
|
(4
|
)
|
|
352
|
|
Total Revenues
|
630
|
|
|
316
|
|
|
(151
|
)
|
|
795
|
|
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
|
360
|
|
|
169
|
|
|
(151
|
)
|
|
378
|
|
Operation and maintenance, General and administrative
|
84
|
|
|
45
|
|
|
—
|
|
|
129
|
|
Depreciation and amortization
|
74
|
|
|
31
|
|
|
—
|
|
|
105
|
|
Taxes other than income tax
|
11
|
|
|
7
|
|
|
—
|
|
|
18
|
|
Operating income
|
$
|
101
|
|
|
$
|
64
|
|
|
$
|
—
|
|
|
$
|
165
|
|
Total Assets
|
$
|
9,934
|
|
|
$
|
5,797
|
|
|
$
|
(3,284
|
)
|
|
$
|
12,447
|
|
Capital expenditures
|
$
|
107
|
|
|
$
|
36
|
|
|
$
|
—
|
|
|
$
|
143
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2018
|
Gathering and
Processing
|
|
Transportation
(1)
and Storage
|
|
Eliminations
|
|
Total
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Product sales
|
$
|
418
|
|
|
$
|
140
|
|
|
$
|
(115
|
)
|
|
$
|
443
|
|
Service revenues
|
173
|
|
|
139
|
|
|
(7
|
)
|
|
305
|
|
Total Revenues
|
591
|
|
|
279
|
|
|
(122
|
)
|
|
748
|
|
Cost of natural gas and natural gas liquids (excluding depreciation and amortization shown separately)
|
358
|
|
|
139
|
|
|
(122
|
)
|
|
375
|
|
Operation and maintenance, General and administrative
|
76
|
|
|
46
|
|
|
(1
|
)
|
|
121
|
|
Depreciation and amortization
|
62
|
|
|
34
|
|
|
—
|
|
|
96
|
|
Taxes other than income tax
|
10
|
|
|
7
|
|
|
—
|
|
|
17
|
|
Operating income
|
$
|
85
|
|
|
$
|
53
|
|
|
$
|
1
|
|
|
$
|
139
|
|
Total assets as of December 31, 2018
|
$
|
9,874
|
|
|
$
|
5,805
|
|
|
$
|
(3,235
|
)
|
|
$
|
12,444
|
|
Capital expenditures
|
$
|
147
|
|
|
$
|
43
|
|
|
$
|
—
|
|
|
$
|
190
|
|
_____________________
|
|
(1)
|
See Note 8 for discussion regarding ownership interests in SESH and related equity earnings included in the transportation and storage segment for the
three
months ended
March 31, 2019
and
2018
.
|