Williams Partners L.P. (NYSE: WPZ) today announced its financial results
for the three and 12 months ended Dec. 31, 2017.
Fourth-Quarter and Full-Year 2017 Highlights
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4Q 2017 Net Income (Loss) of ($342) Million - Impacted by $713 million
of Non-Cash Charges Related to Tax Cuts and Jobs Act of 2017
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Increased 4Q & Full-Year 2017 Adjusted EBITDA to $1.150 Billion and
$4.472 Billion Respectively, Despite over $3 Billion in Asset Sales
Since September 2016
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Cash Distribution Coverage Ratio of 1.22x for 4Q 2017; 1.23x for
Full-Year 2017
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Placed Transco Expansions New York Bay and Virginia Southside II into
Service in 4Q 2017 - Completing Transco's 2017 "Big 5" Expansion
Projects
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Williams Partners Improved Credit Profile, Reducing Net Debt by $2.8
Billion from Jan. 1, 2017 through Dec. 31, 2017
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Williams Partners Exceeded Midpoint of Financial Guidance Targets for
2017, Guidance for 2018 DCF, Distribution Growth (5 to 7%) and
Coverage Remain on Target
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Summary Financial Information
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4Q
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Full Year
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Amounts in millions, except per-unit amounts. Per unit amounts
are reported on a diluted basis. All amounts are attributable to
Williams Partners L.P.
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2017
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2016
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2017
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2016
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GAAP Measures
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Cash Flow from Operations (1)
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$737
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$1,597
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$2,840
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$3,948
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Net income (loss)
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($342
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)
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$145
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$871
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$431
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Net income (loss) per common unit
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($0.35
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$0.24
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$0.90
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($0.17
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Non-GAAP Measures (2)
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Adjusted EBITDA
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$1,150
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$1,113
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$4,472
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$4,427
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DCF attributable to partnership operations
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$702
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$699
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$2,821
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$2,970
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Cash distribution coverage ratio
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1.22x
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0.92x
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1.23x
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1.01x
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(1)
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Cash Flow from Operations was higher in 2016, due primarily to
the receipt of $820 million in cash in the fourth quarter of 2016
associated with certain contract restructurings and prepayments.
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(2)
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Adjusted EBITDA, distributable cash flow (DCF) and cash
distribution coverage ratio are non-GAAP measures. Reconciliations
to the most relevant measures included in GAAP are attached to
this news release.
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Fourth-Quarter and Full-Year 2017 Financial Results
Williams Partners reported unaudited fourth-quarter 2017 net income
(loss) attributable to controlling interests of ($342) million, a $487
million decrease from fourth-quarter 2016. The unfavorable change was
driven primarily by the impact of $713 million of non-cash charges at
Transco and Northwest Pipeline primarily related to regulatory
liabilities established as a result of the recently enacted Tax Cuts and
Jobs Act of 2017 ("Tax Reform Act"). Some of the rates charged to
customers of our regulated natural gas pipelines are subject to periodic
FERC rate case filings, which permit the recovery of an income tax
allowance that includes a deferred income tax component in our recourse
rates. As a result of the reduced income tax rate from the Tax Reform
Act and the resulting regulatory liabilities, we expect that any future
rate case settlements or proceedings before the FERC will be impacted by
this lower income tax allowance. However, the actual amount and timing
of any return of this regulatory liability to customers will be subject
to negotiations in future rate proceedings. We expect that the
amortization of the regulatory liability will be over an extended period
of time (as much as 20 years or more). Considering all of these recourse
rate-making elements, Transco still expects to file for increased
cost-of-service rates in its upcoming initial rate filing in 2018.
Fourth-quarter 2017 results were positively impacted by the absence of
an impairment on equity method investments in fourth-quarter 2016.
For the year, Williams Partners reported unaudited net income
attributable to controlling interests of $871 million, a $440 million
improvement compared to full-year 2016 results. The favorable change was
driven primarily by gains on the sale of assets, the absence of
impairments of equity-method investments, and higher revenues for the
Atlantic-Gulf segment. Partially offsetting the increases was the impact
of the non-cash charges related to the Tax Reform Act as described in
the previous paragraph, a net increase in impairments of certain assets,
and the absence of results associated with the Geismar olefins facility,
which was sold July 6, 2017.
Williams Partners reported fourth-quarter 2017 Adjusted EBITDA of $1.150
billion, a $37 million increase over fourth-quarter 2016. Williams
Partners' current businesses increased Adjusted EBITDA by $84 million in
fourth-quarter 2017 vs. fourth-quarter 2016, driven by $117 million
increased fee-based revenues, due primarily to the growth in fee-based
revenues in the Atlantic-Gulf and West segments partially offset by $30
million in higher operating and maintenance (O&M) expenses. The $84
million improvement from the current businesses was partially offset by
the absence of $47 million Adjusted EBITDA earned in fourth-quarter 2016
from the NGL & Petchem Services segment primarily as a result of the
sale of the Geismar olefins facility on July 6, 2017.
For the year, Williams Partners reported Adjusted EBITDA of $4.472
billion, a $45 million increase over full-year 2016 results. Williams
Partners' current businesses increased Adjusted EBITDA by $202 million
in 2017 compared to 2016. The improvement was due primarily to a $147
million increase in fee-based revenues driven primarily from new assets
brought online by the Atlantic-Gulf segment. The partnership's full-year
2017 results also benefited from $51 million increased commodity margins
and $28 million higher EBITDA from joint ventures, partially offset by
$63 million higher O&M expenses. The $202 million improvement from the
current businesses was partially offset by the absence of $157 million
Adjusted EBITDA earned in 2016 from the NGL & Petchem Services segment
primarily as a result of the sale of the Geismar olefins facility on
July 6, 2017.
Distributable Cash Flow and Distributions
For fourth-quarter 2017, Williams Partners generated $702 million in
distributable cash flow (DCF) attributable to partnership operations,
compared with $699 million in DCF attributable to partnership operations
for fourth-quarter 2016. DCF was favorably impacted by the partnership's
change in Adjusted EBITDA and a $31 million decrease in interest
expense. DCF for fourth-quarter 2017 was reduced by $58 million for the
removal of deferred revenue amortization associated with the
fourth-quarter 2016 contract restructurings and prepayments in the
Barnett Shale and Mid-Continent region. For fourth-quarter 2017, the
cash distribution coverage ratio was 1.22x.
For the year, Williams Partners generated $2.821 billion in DCF
attributable to partnership operations, an unfavorable change of $149
million compared with full-year 2016 DCF results. For 2017, DCF was
reduced by $233 million for the deferred revenue amortization associated
with the previously described contract restructurings and prepayments.
Also impacting DCF for full-year 2017 was $42 million increased
maintenance capital expenditures. Partially offsetting these unfavorable
changes were a $114 million decrease in interest expense and a $45
million improvement in Adjusted EBITDA. As described above, the
partnership's Adjusted EBITDA from current businesses increased $202
million, but was partially offset by $157 million lower Adjusted EBITDA
from assets sold. For full-year 2017, the cash distribution coverage was
1.23x. Both DCF and coverage exceeded the midpoint of financial guidance
provided in January 2017.
Williams Partners recently announced a regular quarterly cash
distribution of $0.60 per unit, payable Feb. 9, 2018, to its common
unitholders of record at the close of business on Feb. 2, 2018.
CEO Perspective
Alan Armstrong, chief executive officer of Williams Partners’ general
partner, made the following comments:
"I am pleased with the organization's strong execution in 2017. Our
organization has been working hard to keep its promises to our
customers, shareholders, and other stakeholders with timely and safe
delivery of our projects, including Transco’s ‘Big 5’ projects (Gulf
Trace, Hillabee Phase 1, Dalton, New York Bay and Virginia Southside
II). This is reflected in our financial results where we exceeded the
midpoint of our guidance range for Adjusted EBITDA, DCF and Cash
Coverage ratios.
"We achieved these impressive results, which include improvement in
year-over-year Adjusted EBITDA for both fourth-quarter and full-year
2017, in spite of the impact of multiple hurricanes and more than $3
billion in asset sales since September 2016. Our stable foundation of
demand-driven expansions continues to grow our business. In 2018, we
look forward to a full year of revenue from our ‘Big 5’ as well as
contributions from our Atlantic Sunrise project later this year and the
associated growth in Northeast gathering volumes.
"We also carried out our financial repositioning in January of 2017 in a
way that positioned the company to fund an attractive slate of
large-scale expansion projects without accessing public equity markets,
strengthened distribution coverage, enhanced our credit profile,
improved our cost of capital and underpinned our growth outlook. As a
result of a full year of executing on the key aspects of our plan, we
reduced WPZ Net Debt for the year by 15 percent and also dramatically
reduced our commodity exposure.
"As the Atlantic Sunrise project construction continues, the
debottlenecking of the Northeast is starting to occur as other pipelines
in the Northeast have also been placed in service recently or will be
brought online in the near future. We are beginning to see some of the
key fundamentals of our strategy take shape in the Northeast where we
have a leading market share and a path to deliver long-term sustainable
shareholder value. Volumes are increasing and our focus on executing the
company’s natural gas-focused business strategy is producing predictable
fee-based revenue growth backed by long-term commitments."
Business Segment Results
For full-year 2017 results, Williams Partners' operations are comprised
of the following reportable segments: Atlantic-Gulf, West, Northeast
G&P, and NGL & Petchem Services. As of July 7, 2017, following the
completed sale of Williams Partners' ownership interest in the Geismar
olefins plant on July 6, 2017, the partnership's NGL & Petchem Services
segment no longer contained any operating assets.
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Amounts in millions
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4Q 2017
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4Q 2016
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YTD 2017
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YTD 2016
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Modified
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Adjusted
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Modified
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Adjusted
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Modified
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Adjusted
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Modified
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Adjusted
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EBITDA
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Adjust.
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EBITDA
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EBITDA
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Adjust.
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EBITDA
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EBITDA
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Adjust.
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EBITDA
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EBITDA
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Adjust.
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EBITDA
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Atlantic-Gulf
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($96
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$529
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$433
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$456
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($2
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$454
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$1,238
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$541
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$1,779
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$1,621
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$40
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$1,661
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West
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286
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195
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481
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542
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(148
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394
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412
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1,256
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1,668
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1,544
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107
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1,651
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Northeast G&P
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231
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7
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238
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197
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22
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219
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819
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140
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959
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853
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33
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886
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NGL & Petchem Services
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(4
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3
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(1
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49
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(3
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46
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1,161
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(1,089
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72
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(145
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374
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229
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Other
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(9
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8
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(1
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(9
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9
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—
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(14
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8
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(6
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(9
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9
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—
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Total
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$408
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$742
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$1,150
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$1,235
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($122
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$1,113
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$3,616
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$856
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$4,472
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$3,864
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$563
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$4,427
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Williams Partners uses Modified EBITDA for its segment reporting.
Definitions of Modified EBITDA and Adjusted EBITDA and schedules
reconciling these measures to net income are included in this news
release.
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Atlantic-Gulf
This segment includes the partnership’s interstate natural gas pipeline,
Transco, and significant natural gas gathering and processing and crude
oil production handling and transportation assets in the Gulf Coast
region, including a 51 percent interest in Gulfstar One (a consolidated
entity), which is a proprietary floating production system, and various
petrochemical and feedstock pipelines in the Gulf Coast region, as well
as a 50 percent equity-method investment in Gulfstream, a 41 percent
interest in Constitution (a consolidated entity) which is developing a
pipeline project, and a 60 percent equity-method investment in Discovery.
The Atlantic-Gulf segment reported Modified EBITDA of ($96) million for
fourth-quarter 2017, compared with $456 million for fourth-quarter 2016.
Adjusted EBITDA decreased by $21 million to $433 million for the same
time period. The unfavorable change in Modified EBITDA was due primarily
to the impact of $493 million of non-cash charges at Transco primarily
related to regulatory liabilities resulting from the Tax Reform Act and
previously described in this news release. The Tax Reform Act also led
to non-cash charges of $11 million of proportional Modified EBITDA of
joint-ventures from Transco's investments. The non-cash charges
associated with the Tax Reform Act did not impact 2017 Adjusted EBITDA.
The segment benefited from a $57 million increase in fee-based revenues
from Transco expansion projects brought online. Partially offsetting the
improvement were $32 million increased O&M expenses primarily associated
with Transco's integrity and pipeline maintenance programs and $20
million decreased proportional EBITDA from the partnership's Discovery
joint venture, due to a significant decline in volumes from the Hadrian
field. Results for fourth-quarter 2017 also reflect the absence of $22
million in fee-based revenues and commodity margins from volumes
transported and processed by Williams Partners on a short-term basis due
to an unplanned outage on another company's system in 2016.
For the year, Atlantic-Gulf reported Modified EBITDA of $1.238 billion,
a decrease of $383 million from full-year 2016. Adjusted EBITDA
increased $118 million to $1.779 billion. The unfavorable change in
Modified EBITDA was due primarily to the impact of the non-cash charges
associated with the Tax Reform Act referenced in the previous paragraph.
Adjusted EBITDA benefited from $132 million increased fee-based revenues
primarily from Transco expansion projects brought online, and a $104
million improvement from Gulfstar One. Partially offsetting the
increases were $90 million higher O&M expenses primarily associated with
Transco's integrity and pipeline maintenance programs. Results for
full-year 2017 also reflect the absence of $42 million in fee-based
revenues and commodity margins from volumes transported and processed by
Williams Partners on a short-term basis due to an unplanned outage on
another company's system in 2016.
West
This segment includes the partnership’s interstate natural gas pipeline,
Northwest Pipeline, and natural gas gathering, processing, and treating
operations in New Mexico, Colorado, and Wyoming, as well as the Barnett
Shale region of north-central Texas, the Eagle Ford Shale region of
south Texas, the Haynesville Shale region of northwest Louisiana, and
the Mid-Continent region which includes the Anadarko, Arkoma, Delaware
and Permian basins. This reporting segment also includes an NGL and
natural gas marketing business, storage facilities, and an undivided 50
percent interest in an NGL fractionator near Conway, Kansas, and a 50
percent equity-method investment in OPPL. The partnership completed the
sale of its 50 percent equity-method investment in a Delaware Basin gas
gathering system in the Mid-Continent region during first-quarter 2017.
The West segment reported Modified EBITDA of $286 million for
fourth-quarter 2017, compared with $542 million for fourth-quarter 2016.
Adjusted EBITDA increased by $87 million to $481 million. The
unfavorable change in Modified EBITDA was due primarily to the impact of
$220 million of non-cash charges at Northwest Pipeline primarily related
to regulatory liabilities resulting from the Tax Reform Act and
previously described in this press release. Adjusted EBITDA, which is
not impacted by the non-cash charges associated with the Tax Reform Act,
benefited from $54 million higher fee-based revenues due to increased
volumes primarily in the Haynesville, other rate changes, and a $24
million positive impact from the 2016 Barnett contract restructuring and
prepayment. The year-over-year comparison for the quarter also benefited
from $16 million improved commodity margins and $20 million in lower O&M
and selling, general and administrative (SG&A) expenses. Partially
offsetting these improvements was $10 million decreased proportional
EBITDA from joint ventures, due in part to the partnership's sale of its
interests in certain non-operated Delaware Basin assets in first-quarter
2017.
For the year, the West segment reported Modified EBITDA of $412 million,
a decrease of $1.132 billion from full-year 2016 results. Adjusted
EBITDA increased by $17 million to $1.668 billion. The unfavorable
change in Modified EBITDA is due primarily to a $1.019 billion
impairment of certain gathering operations in the Mid-Continent region
and the non-cash charges associated with the Tax Reform Act described in
the previous paragraph. Adjusted EBITDA excludes the impairment charge
and is not impacted by the non-cash charges associated with the Tax
Reform Act. The favorable change in Adjusted EBITDA reflects $73 million
lower O&M and SG&A expenses and $54 million improved commodity margins.
Revenues were also impacted by lower rates associated with 2016 contract
restructurings and lower volumes driven by natural declines, partially
offset by the amortization of deferred revenue from those 2016 contract
restructurings and prepayments. As a result, Adjusted EBITDA reflects
$87 million of lower fee-based revenues. When compared to full-year 2016
results, the segment was also negatively impacted by $31 million in
decreased proportional EBITDA of joint ventures, due in part to the
partnership’s sale of its interests in certain non-operated Delaware
Basin assets in first-quarter 2017.
Northeast G&P
This segment includes the partnership’s natural gas gathering and
processing, compression and NGL fractionation businesses in the
Marcellus Shale region primarily in Pennsylvania, New York, and West
Virginia and Utica Shale region of eastern Ohio, as well as a 66 percent
interest in Cardinal (a consolidated entity), a 62 percent equity-method
investment in UEOM, a 69 percent equity-method investment in Laurel
Mountain, a 58 percent equity-method investment in Caiman II, and
Appalachia Midstream Services, LLC, which owns an approximate average 66
percent equity-method investment in multiple gas gathering systems in
the Marcellus Shale (Appalachia Midstream Investments).
The Northeast G&P segment reported Modified EBITDA of $231 million for
fourth-quarter 2017, compared with $197 million for fourth-quarter 2016.
Adjusted EBITDA increased by $19 million to $238 million. The current
year benefited from a $25 million increase in proportional EBITDA of
joint ventures due largely to the partnership's increase in ownership in
two Marcellus shale gathering systems in first-quarter 2017. Fee-based
revenues were stable between the two periods due to increases in the
Susquehanna and Ohio River systems that offset decreases in the Utica.
For the year, the Northeast G&P segment reported Modified EBITDA of $819
million, a decrease of $34 million compared with full-year 2016 results.
Adjusted EBITDA increased by $73 million to $959 million. The
unfavorable change in Modified EBITDA reflected a $115 million
impairment of certain gathering operations in the Marcellus South. The
impairment charge is excluded from Adjusted EBITDA, which benefited from
a $71 million increase in proportional EBITDA of joint ventures due
largely to the partnership's increase in ownership in two Marcellus
shale gathering systems in first-quarter 2017. Fee-based revenues were
stable between the two periods due to increases in the Susquehanna and
Ohio River systems that offset decreases in the Utica.
NGL & Petchem Services
On Jan. 1, 2017, this segment included the partnership’s 88.46 percent
undivided interest in an olefins production facility in Geismar,
Louisiana, along with a refinery grade propylene splitter. On July 6,
2017, the partnership announced that it had completed the sale of all of
its membership interest in the Geismar olefins production facility and
associated complex. On June 30, 2017 the partnership completed the sale
of the refinery grade propylene splitter. Prior to September 2016, this
reporting segment also included an oil sands offgas processing plant
near Fort McMurray, Alberta, and an NGL/olefin fractionation facility,
which were subsequently sold. As of July 7, 2017, this segment no longer
contained any operating assets.
For the year, the NGL & Petchem Services segment reported Modified
EBITDA of $1.161 billion, an improvement of $1.306 billion compared with
full-year 2016 results. Adjusted EBITDA decreased $157 million to $72
million. The improvement in Modified EBITDA was driven primarily by the
$1.095 billion gain resulting from the sale of the partnership's
interest in the Geismar olefins facility on July 6, 2017, and the
absence of a $341 million impairment of our former Canadian operations
in 2016. These items are excluded from Adjusted EBITDA. The current year
was also impacted by the absence of EBITDA associated with the
previously described assets that were sold by the partnership.
Notable Accomplishments
On Dec. 5, 2017, the partnership announced that it had successfully
placed into service its Virginia Southside II expansion project, the
fifth of Transco’s “Big 5” expansions to be placed into service in 2017.
These five, fully-contracted expansion projects (Gulf Trace, Hillabee
Phase 1, Dalton, New York Bay and Virginia Southside II) combined to add
more than 2.8 million dekatherms per day (Dth/d) of firm transportation
capacity to the Transco pipeline system in 2017, contributing to the
increase of Transco’s design capacity by approximately 25 percent.
Williams Partners' Credit Profile Update
The partnership continued to maintain its strengthened balance sheet and
credit profile with nearly $2.1 billion of Total Debt reduction and more
than $700 million increase in cash, year-to-date, resulting in a $2.8
billion reduction in Net Debt (long-term debt plus commercial paper less
cash). As of the end of fourth-quarter 2017, the partnership had Total
Debt of $16.5 billion and cash and cash equivalents of $881 million,
which the partnership intends to use to fund growth capital expenditures
and long-term investments.
2018 Guidance
Current guidance for 2018 is set out in the following table. As noted in
the table below, Williams Partners' Adjusted EBITDA and Distributable
Cash Flow estimates for 2018 have recently been impacted by non-cash
adjustments related to the new GAAP revenue recognition standard and Tax
Reform Act. For Williams Partners' Adjusted EBITDA, the unfavorable
non-cash impacts of these two items were approximately $120 million for
the new GAAP revenue recognition standard and approximately $30 million
for tax reform primarily due to Northwest Pipeline even though rates on
Northwest Pipeline remain unchanged until the next rate case cycle
expected to occur in 2021.
The main effect of the new GAAP revenue recognition standard was to
extend the amortization of deferred revenue associated with certain 2016
contract restructurings and pre-payments by approximately 10 years
resulting in lower 2018 and 2019 revenue and then higher revenue amounts
through 2029. Furthermore, as a result of the extended revenue
amortization period under the new GAAP revenue standard, we have
prospectively discontinued the adjustment which removed the DCF
associated with these 2016 contract restructuring prepayments.
Consequently, DCF is expected to be approximately $140 million higher in
2018 than it otherwise would have been absent this prospective change.
Amounts in billions, except per-unit cash distribution, cash
dividend and coverage ratio amounts. All income
amounts attributable to Williams Partners LP.
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Williams Partners
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2018
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Net income (1)
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$1.5-$1.7
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Adjusted EBITDA (1)(2)(3)
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$4.45-$4.65
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Distributable Cash Flow (1)(2)(4)
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$2.9-$3.2
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Cash Distribution Coverage Ratio (1)(2)(4)
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~1.2x (midpoint of guidance)
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Distribution Growth Rate (3)
(Quarterly Distribution Increases)
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5-7% annual growth for 2018 and 2019
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Total Growth Capital Expenditures
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|
|
$2.7
|
Transco Growth Capital Expenditures
|
|
|
$1.7
|
Leverage (5)
|
|
|
< 4.5x
|
|
|
|
(1)
|
|
Assumes 2018 WTI oil price of approximately $59.00 per barrel and
Henry Hub natural gas price of approximately $2.80 per mmbtu.
|
(2)
|
|
For Williams Partners, Adjusted EBITDA, Distributable Cash Flow
and Cash Distribution Coverage Ratio are non-GAAP measures and for
Williams, Dividend Coverage Ratio is a non-GAAP measure;
reconciliations to the most relevant measures are attached to this
news release.
|
(3)
|
|
Includes $0.15 billion unfavorable effects of new revenue
recognition standard and tax reform. Guidance would be $4.6-$4.8
without these items. See description above.
|
(4)
|
|
Includes $0.14 billion favorable effects associated with changes
in the treatment of certain 2016 contract restructurings. Guidance
would be $2.8-$3.1 without these items. See description above.
|
(5)
|
|
Estimated rating agency adjusted Debt to EBITDA
|
|
|
|
|
|
|
Williams Partners’ Year-End 2017 Materials to be Posted
Shortly; Q&A Webcast Scheduled for Tomorrow
Williams Partners’ fourth-quarter and full-year 2017 financial results
package will be posted shortly at www.williams.com.
Williams Partners and Williams will host a joint Q&A live webcast on
Thursday, Feb. 15 at 9:30 a.m. Eastern Time (8:30 a.m. Central Time). A
limited number of phone lines will be available at (888) 468-2440.
International callers should dial (719) 325-4790. The conference ID is
2010872. The link to the webcast, as well as replays of the webcast,
will be available for at least 90 days following the event at www.williams.com.
Form 10-K
The partnership plans to file its 2017 Form 10-K with the Securities and
Exchange Commission (SEC) next week. Once filed, the document will be
available on both the SEC and Williams Partners websites.
Definitions of Non-GAAP Measures
This news release and accompanying materials may include certain
financial measures – Adjusted EBITDA, distributable cash flow and cash
distribution coverage ratio – that are non-GAAP financial measures as
defined under the rules of the SEC.
Our segment performance measure, Modified EBITDA, is defined as net
income (loss) before income tax expense, net interest expense, equity
earnings from equity-method investments, other net investing income,
impairments of equity investments and goodwill, depreciation and
amortization expense, and accretion expense associated with asset
retirement obligations for nonregulated operations. We also add our
proportional ownership share (based on ownership interest) of Modified
EBITDA of equity-method investments.
Adjusted EBITDA further excludes items of income or loss that we
characterize as unrepresentative of our ongoing operations. Management
believes these measures provide investors meaningful insight into
results from ongoing operations.
We define distributable cash flow as Adjusted EBITDA less maintenance
capital expenditures, cash portion of interest expense, income
attributable to noncontrolling interests and cash income taxes, plus WPZ
restricted stock unit non-cash compensation expense and certain other
adjustments that management believes affects the comparability of
results. Adjustments for maintenance capital expenditures and cash
portion of interest expense include our proportionate share of these
items of our equity-method investments.
We also calculate the ratio of distributable cash flow to the total cash
distributed (cash distribution coverage ratio). This measure reflects
the amount of distributable cash flow relative to our cash distribution.
We have also provided this ratio using the most directly comparable GAAP
measure, net income (loss).
This news release is accompanied by a reconciliation of these non-GAAP
financial measures to their nearest GAAP financial measures. Management
uses these financial measures because they are accepted financial
indicators used by investors to compare company performance. In
addition, management believes that these measures provide investors an
enhanced perspective of the operating performance of the Partnership's
assets and the cash that the business is generating.
Neither Adjusted EBITDA nor distributable cash flow are intended to
represent cash flows for the period, nor are they presented as an
alternative to net income or cash flow from operations. They should not
be considered in isolation or as substitutes for a measure of
performance prepared in accordance with United States generally accepted
accounting principles.
About Williams Partners
Williams Partners is an industry-leading, large-cap natural gas
infrastructure master limited partnership with a strong growth outlook
and major positions in key U.S. supply basins. Williams Partners has
operations across the natural gas value chain including gathering,
processing and interstate transportation of natural gas and natural gas
liquids. Williams Partners owns and operates more than 33,000 miles of
pipelines system wide – including the nation’s largest volume and
fastest growing pipeline – providing natural gas for clean-power
generation, heating and industrial use. Williams Partners’ operations
touch approximately 30 percent of U.S. natural gas. Tulsa, Okla.-based
Williams (NYSE: WMB), a premier provider of large-scale U.S. natural gas
infrastructure, owns approximately 74 percent of Williams Partners.
Forward-Looking Statements
The reports, filings, and other public announcements of Williams
Partners L.P. (WPZ) may contain or incorporate by reference statements
that do not directly or exclusively relate to historical facts. Such
statements are “forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933, as amended (Securities Act)
and Section 21E of the Securities Exchange Act of 1934, as amended
(Exchange Act). These forward-looking statements relate to anticipated
financial performance, management’s plans and objectives for future
operations, business prospects, outcome of regulatory proceedings,
market conditions and other matters.
All statements, other than statements of historical facts, included
herein that address activities, events or developments that we expect,
believe or anticipate will exist or may occur in the future, are
forward-looking statements. Forward-looking statements can be identified
by various forms of words such as “anticipates,” “believes,” “seeks,”
“could,” “may,” “should,” “continues,” “estimates,” “expects,”
“forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,”
“planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,”
“guidance,” “outlook,” “in-service date” or other similar expressions.
These forward-looking statements are based on management’s beliefs and
assumptions and on information currently available to management and
include, among others, statements regarding:
-
Levels of cash distributions with respect to limited partner
interests;
-
Our and our affiliates’ future credit ratings;
-
Amounts and nature of future capital expenditures;
-
Expansion and growth of our business and operations;
-
Expected in-service dates for capital projects;
-
Financial condition and liquidity;
-
Business strategy;
-
Cash flow from operations or results of operations;
-
Seasonality of certain business components;
-
Natural gas and natural gas liquids prices, supply, and demand;
-
Demand for our services.
Forward-looking statements are based on numerous assumptions,
uncertainties and risks that could cause future events or results to be
materially different from those stated or implied herein. Many of the
factors that will determine these results are beyond our ability to
control or predict. Specific factors that could cause actual results to
differ from results contemplated by the forward-looking statements
include, among others, the following:
-
Whether we will produce sufficient cash flows to provide expected
levels of cash distributions;
-
Whether we elect to pay expected levels of cash distributions;
-
Whether we will be able to effectively execute our financing plan;
-
Whether Williams will be able to effectively manage the transition
in its board of directors and management as well as successfully
execute its business restructuring;
-
Availability of supplies, including lower than anticipated volumes
from third parties served by our business, and market demand;
-
Volatility of pricing including the effect of lower than
anticipated energy commodity prices and margins;
-
Inflation, interest rates, and general economic conditions
(including future disruptions and volatility in the global credit
markets and the impact of these events on customers and suppliers);
-
The strength and financial resources of our competitors and the
effects of competition;
-
Whether we are able to successfully identify, evaluate, and timely
execute our capital projects and other investment opportunities in
accordance with our forecasted capital expenditures budget;
-
Our ability to successfully expand our facilities and operations;
-
Development and rate of adoption of alternative energy sources;
-
The impact of operational and developmental hazards, unforeseen
interruptions, and the availability of adequate insurance coverage;
-
The impact of existing and future laws (including but not limited
to the Tax Cuts and Jobs Act of 2017), regulations, the regulatory
environment, environmental liabilities, and litigation, as well as our
ability to obtain necessary permits and approvals, and achieve
favorable rate proceeding outcomes;
-
Our costs for defined benefit pension plans and other
postretirement benefit plans sponsored by our affiliates;
-
Changes in maintenance and construction costs;
-
Changes in the current geopolitical situation;
-
Our exposure to the credit risk of our customers and counterparties;
-
Risks related to financing, including restrictions stemming from
debt agreements, future changes in credit ratings as determined by
nationally-recognized credit rating agencies and the availability and
cost of capital;
-
The amount of cash distributions from and capital requirements of
our investments and joint ventures in which we participate;
-
Risks associated with weather and natural phenomena, including
climate conditions and physical damage to our facilities;
-
Acts of terrorism, including cybersecurity threats, and related
disruptions;
-
Additional risks described in our filings with the Securities and
Exchange Commission (SEC).
Given the uncertainties and risk factors that could cause our actual
results to differ materially from those contained in any forward-looking
statement, we caution investors not to unduly rely on our
forward-looking statements. We disclaim any obligations to and do not
intend to update the above list or announce publicly the result of any
revisions to any of the forward-looking statements to reflect future
events or developments.
In addition to causing our actual results to differ, the factors
listed above may cause our intentions to change from those statements of
intention set forth herein. Such changes in our intentions may also
cause our results to differ. We may change our intentions, at any time
and without notice, based upon changes in such factors, our assumptions,
or otherwise.
Limited partner units are inherently different from the capital stock
of a corporation, although many of the business risks to which we are
subject are similar to those that would be faced by a corporation
engaged in a similar business. You should carefully consider the risk
factors discussed above in addition to the other information contained
herein. If any of such risks were actually to occur, our business,
results of operations, and financial condition could be materially
adversely affected. In that case, we might not be able to pay
distributions on our common units, the trading price of our common units
could decline, and unitholders could lose all or part of their
investment.
Because forward-looking statements involve risks and uncertainties,
we caution that there are important factors, in addition to those listed
above, that may cause actual results to differ materially from those
contained in the forward-looking statements. For a detailed discussion
of those factors, see Part I, Item 1A. Risk Factors in our Annual Report
on Form 10-K filed with the SEC on February 22, 2017.
|
|
Williams Partners L.P.
|
Reconciliation of Non-GAAP Measures
|
(UNAUDITED)
|
|
|
|
2016
|
|
|
2017
|
(Dollars in millions, except coverage ratios)
|
|
|
1st Qtr
|
|
|
2nd Qtr
|
|
|
3rd Qtr
|
|
|
4th Qtr
|
|
|
Year
|
|
|
1st Qtr
|
|
|
2nd Qtr
|
|
|
3rd Qtr
|
|
|
4th Qtr
|
|
|
Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of "Net Income (Loss)" to "Modified EBITDA",
Non-GAAP "Adjusted EBITDA" and "Distributable cash flow"
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$
|
79
|
|
|
|
$
|
(77
|
)
|
|
|
$
|
351
|
|
|
|
$
|
166
|
|
|
|
$
|
519
|
|
|
|
$
|
660
|
|
|
|
$
|
348
|
|
|
|
$
|
284
|
|
|
|
$
|
(317
|
)
|
|
|
$
|
975
|
|
Provision (benefit) for income taxes
|
|
|
|
1
|
|
|
|
|
(80
|
)
|
|
|
|
(6
|
)
|
|
|
|
5
|
|
|
|
|
(80
|
)
|
|
|
|
3
|
|
|
|
|
1
|
|
|
|
|
(1
|
)
|
|
|
|
3
|
|
|
|
|
6
|
|
Interest expense
|
|
|
|
229
|
|
|
|
|
231
|
|
|
|
|
229
|
|
|
|
|
227
|
|
|
|
|
916
|
|
|
|
|
214
|
|
|
|
|
205
|
|
|
|
|
202
|
|
|
|
|
201
|
|
|
|
|
822
|
|
Equity (earnings) losses
|
|
|
|
(97
|
)
|
|
|
|
(101
|
)
|
|
|
|
(104
|
)
|
|
|
|
(95
|
)
|
|
|
|
(397
|
)
|
|
|
|
(107
|
)
|
|
|
|
(125
|
)
|
|
|
|
(115
|
)
|
|
|
|
(87
|
)
|
|
|
|
(434
|
)
|
Impairment of equity-method investments
|
|
|
|
112
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
318
|
|
|
|
|
430
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
Other investing (income) loss - net
|
|
|
|
—
|
|
|
|
|
(1
|
)
|
|
|
|
(28
|
)
|
|
|
|
—
|
|
|
|
|
(29
|
)
|
|
|
|
(271
|
)
|
|
|
|
(2
|
)
|
|
|
|
(4
|
)
|
|
|
|
(4
|
)
|
|
|
|
(281
|
)
|
Proportional Modified EBITDA of equity-method investments
|
|
|
|
189
|
|
|
|
|
191
|
|
|
|
|
194
|
|
|
|
|
180
|
|
|
|
|
754
|
|
|
|
|
194
|
|
|
|
|
215
|
|
|
|
|
202
|
|
|
|
|
184
|
|
|
|
|
795
|
|
Depreciation and amortization expenses
|
|
|
|
435
|
|
|
|
|
432
|
|
|
|
|
426
|
|
|
|
|
427
|
|
|
|
|
1,720
|
|
|
|
|
433
|
|
|
|
|
423
|
|
|
|
|
424
|
|
|
|
|
420
|
|
|
|
|
1,700
|
|
Accretion expense associated with asset retirement obligations for
nonregulated operations
|
|
|
|
7
|
|
|
|
|
9
|
|
|
|
|
8
|
|
|
|
|
7
|
|
|
|
|
31
|
|
|
|
|
6
|
|
|
|
|
11
|
|
|
|
|
8
|
|
|
|
|
8
|
|
|
|
|
33
|
|
Modified EBITDA
|
|
|
|
955
|
|
|
|
|
604
|
|
|
|
|
1,070
|
|
|
|
|
1,235
|
|
|
|
|
3,864
|
|
|
|
|
1,132
|
|
|
|
|
1,076
|
|
|
|
|
1,000
|
|
|
|
|
408
|
|
|
|
|
3,616
|
|
Adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated minimum volume commitments
|
|
|
|
60
|
|
|
|
|
64
|
|
|
|
|
70
|
|
|
|
|
(194
|
)
|
|
|
|
—
|
|
|
|
|
15
|
|
|
|
|
15
|
|
|
|
|
18
|
|
|
|
|
(48
|
)
|
|
|
|
—
|
|
Severance and related costs
|
|
|
|
25
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
12
|
|
|
|
|
37
|
|
|
|
|
9
|
|
|
|
|
4
|
|
|
|
|
5
|
|
|
|
|
4
|
|
|
|
|
22
|
|
Potential rate refunds associated with rate case litigation
|
|
|
|
15
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
15
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
Settlement charge from pension early payout program
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
35
|
|
|
|
|
35
|
|
Regulatory charges resulting from Tax Reform
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
713
|
|
|
|
|
713
|
|
Share of regulatory charges resulting from Tax Reform for
equity-method investments
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
11
|
|
|
|
|
11
|
|
ACMP Merger and transition costs
|
|
|
|
5
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
5
|
|
|
|
|
—
|
|
|
|
|
4
|
|
|
|
|
3
|
|
|
|
|
4
|
|
|
|
|
11
|
|
Constitution Pipeline project development costs
|
|
|
|
—
|
|
|
|
|
8
|
|
|
|
|
11
|
|
|
|
|
9
|
|
|
|
|
28
|
|
|
|
|
2
|
|
|
|
|
6
|
|
|
|
|
4
|
|
|
|
|
4
|
|
|
|
|
16
|
|
Share of impairment at equity-method investment
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
6
|
|
|
|
|
19
|
|
|
|
|
25
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
1
|
|
|
|
|
—
|
|
|
|
|
1
|
|
Geismar Incident adjustment
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(7
|
)
|
|
|
|
(7
|
)
|
|
|
|
(9
|
)
|
|
|
|
2
|
|
|
|
|
8
|
|
|
|
|
(1
|
)
|
|
|
|
—
|
|
Gain on sale of Geismar Interest
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(1,095
|
)
|
|
|
|
—
|
|
|
|
|
(1,095
|
)
|
Impairment of certain assets
|
|
|
|
—
|
|
|
|
|
389
|
|
|
|
|
—
|
|
|
|
|
22
|
|
|
|
|
411
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
1,142
|
|
|
|
|
9
|
|
|
|
|
1,151
|
|
Ad valorem obligation timing adjustment
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
7
|
|
|
|
|
—
|
|
|
|
|
7
|
|
Organizational realignment-related costs
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
24
|
|
|
|
|
24
|
|
|
|
|
4
|
|
|
|
|
6
|
|
|
|
|
6
|
|
|
|
|
2
|
|
|
|
|
18
|
|
Loss related to Canada disposition
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
32
|
|
|
|
|
2
|
|
|
|
|
34
|
|
|
|
|
(3
|
)
|
|
|
|
(1
|
)
|
|
|
|
4
|
|
|
|
|
4
|
|
|
|
|
4
|
|
Gain on asset retirement
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(11
|
)
|
|
|
|
(11
|
)
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(5
|
)
|
|
|
|
5
|
|
|
|
|
—
|
|
Gains from contract settlements and terminations
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(13
|
)
|
|
|
|
(2
|
)
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(15
|
)
|
Accrual for loss contingency
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
9
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
9
|
|
Gain on early retirement of debt
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(30
|
)
|
|
|
|
—
|
|
|
|
|
3
|
|
|
|
|
—
|
|
|
|
|
(27
|
)
|
Gain on sale of RGP Splitter
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(12
|
)
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(12
|
)
|
Expenses associated with Financial Repositioning
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
2
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
2
|
|
Expenses associated with strategic asset monetizations
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
2
|
|
|
|
|
2
|
|
|
|
|
1
|
|
|
|
|
4
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
5
|
|
Total EBITDA adjustments
|
|
|
|
105
|
|
|
|
|
461
|
|
|
|
|
119
|
|
|
|
|
(122
|
)
|
|
|
|
563
|
|
|
|
|
(15
|
)
|
|
|
|
28
|
|
|
|
|
101
|
|
|
|
|
742
|
|
|
|
|
856
|
|
Adjusted EBITDA
|
|
|
|
1,060
|
|
|
|
|
1,065
|
|
|
|
|
1,189
|
|
|
|
|
1,113
|
|
|
|
|
4,427
|
|
|
|
|
1,117
|
|
|
|
|
1,104
|
|
|
|
|
1,101
|
|
|
|
|
1,150
|
|
|
|
|
4,472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures (1)
|
|
|
|
(58
|
)
|
|
|
|
(75
|
)
|
|
|
|
(121
|
)
|
|
|
|
(147
|
)
|
|
|
|
(401
|
)
|
|
|
|
(53
|
)
|
|
|
|
(100
|
)
|
|
|
|
(136
|
)
|
|
|
|
(154
|
)
|
|
|
|
(443
|
)
|
Interest expense (cash portion) (2)
|
|
|
|
(241
|
)
|
|
|
|
(245
|
)
|
|
|
|
(244
|
)
|
|
|
|
(239
|
)
|
|
|
|
(969
|
)
|
|
|
|
(224
|
)
|
|
|
|
(216
|
)
|
|
|
|
(207
|
)
|
|
|
|
(208
|
)
|
|
|
|
(855
|
)
|
Cash taxes
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(3
|
)
|
|
|
|
(3
|
)
|
|
|
|
(5
|
)
|
|
|
|
(1
|
)
|
|
|
|
(4
|
)
|
|
|
|
(2
|
)
|
|
|
|
(12
|
)
|
Income attributable to noncontrolling interests (3)
|
|
|
|
(29
|
)
|
|
|
|
(13
|
)
|
|
|
|
(31
|
)
|
|
|
|
(27
|
)
|
|
|
|
(100
|
)
|
|
|
|
(27
|
)
|
|
|
|
(32
|
)
|
|
|
|
(27
|
)
|
|
|
|
(27
|
)
|
|
|
|
(113
|
)
|
WPZ restricted stock unit non-cash compensation
|
|
|
|
7
|
|
|
|
|
5
|
|
|
|
|
2
|
|
|
|
|
2
|
|
|
|
|
16
|
|
|
|
|
2
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
5
|
|
Amortization of deferred revenue associated with certain 2016
contract restructurings
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(58
|
)
|
|
|
|
(58
|
)
|
|
|
|
(59
|
)
|
|
|
|
(58
|
)
|
|
|
|
(233
|
)
|
Distributable cash flow attributable to Partnership Operations (4)
|
|
|
|
739
|
|
|
|
|
737
|
|
|
|
|
795
|
|
|
|
|
699
|
|
|
|
|
2,970
|
|
|
|
|
752
|
|
|
|
|
698
|
|
|
|
|
669
|
|
|
|
|
702
|
|
|
|
|
2,821
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash distributed (5)
|
|
|
$
|
725
|
|
|
|
$
|
725
|
|
|
|
$
|
734
|
|
|
|
$
|
762
|
|
|
|
$
|
2,946
|
|
|
|
$
|
567
|
|
|
|
$
|
574
|
|
|
|
$
|
574
|
|
|
|
$
|
574
|
|
|
|
$
|
2,289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coverage ratios:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow attributable to partnership operations
divided by Total cash distributed
|
|
|
|
1.02
|
|
|
|
|
1.02
|
|
|
|
|
1.08
|
|
|
|
|
0.92
|
|
|
|
|
1.01
|
|
|
|
|
1.33
|
|
|
|
|
1.22
|
|
|
|
|
1.17
|
|
|
|
|
1.22
|
|
|
|
|
1.23
|
|
Net income (loss) divided by Total cash distributed
|
|
|
|
0.11
|
|
|
|
|
(0.11
|
)
|
|
|
|
0.48
|
|
|
|
|
0.22
|
|
|
|
|
0.18
|
|
|
|
|
1.16
|
|
|
|
|
0.61
|
|
|
|
|
0.49
|
|
|
|
|
(0.55
|
)
|
|
|
|
0.43
|
|
(1)
|
|
Includes proportionate share of maintenance capital expenditures
of equity investments.
|
(2)
|
|
Includes proportionate share of interest expense of equity
investments.
|
(3)
|
|
Excludes allocable share of certain EBITDA adjustments.
|
(4)
|
|
The fourth quarter of 2016 includes income of $183 million
associated with proceeds from the contract restructuring in the
Barnett Shale and Mid-Continent region as the cash was received
during 2016.
|
(5)
|
|
In order to exclude the impact of the IDR waiver associated with
the WPZ merger termination fee from the determination of coverage
ratios, cash distributions have been increased by $10 million in
the first quarter of 2016. Cash distributions for the third
quarter of 2016 have been increased to exclude the impact of the
$150 million IDR waiver associated with the sale of our Canadian
operations. Cash distributions for the fourth quarter of 2016 and
the first quarter of 2017 have been decreased by $50 million and
$6 million, respectively, to reflect the amount paid by WMB to WPZ
pursuant to the January 2017 Common Unit Purchase Agreement.
|
|
|
Williams Partners L.P.
|
Reconciliation of “Modified EBITDA” to Non-GAAP “Adjusted EBITDA”
|
(UNAUDITED)
|
|
|
|
2016
|
|
|
2017
|
(Dollars in millions)
|
|
|
1st Qtr
|
|
|
2nd Qtr
|
|
|
3rd Qtr
|
|
|
4th Qtr
|
|
|
Year
|
|
|
1st Qtr
|
|
|
2nd Qtr
|
|
|
3rd Qtr
|
|
|
4th Qtr
|
|
|
Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Modified EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast G&P
|
|
|
$
|
220
|
|
|
$
|
222
|
|
|
|
$
|
214
|
|
|
$
|
197
|
|
|
|
$
|
853
|
|
|
|
$
|
226
|
|
|
|
$
|
247
|
|
|
|
$
|
115
|
|
|
|
$
|
231
|
|
|
|
$
|
819
|
|
Atlantic-Gulf
|
|
|
|
382
|
|
|
|
360
|
|
|
|
|
423
|
|
|
|
456
|
|
|
|
|
1,621
|
|
|
|
|
450
|
|
|
|
|
454
|
|
|
|
|
430
|
|
|
|
|
(96
|
)
|
|
|
|
1,238
|
|
West
|
|
|
|
327
|
|
|
|
312
|
|
|
|
|
363
|
|
|
|
542
|
|
|
|
|
1,544
|
|
|
|
|
385
|
|
|
|
|
356
|
|
|
|
|
(615
|
)
|
|
|
|
286
|
|
|
|
|
412
|
|
NGL & Petchem Services
|
|
|
|
26
|
|
|
|
(290
|
)
|
|
|
|
70
|
|
|
|
49
|
|
|
|
|
(145
|
)
|
|
|
|
51
|
|
|
|
|
30
|
|
|
|
|
1,084
|
|
|
|
|
(4
|
)
|
|
|
|
1,161
|
|
Other
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
(9
|
)
|
|
|
|
(9
|
)
|
|
|
|
20
|
|
|
|
|
(11
|
)
|
|
|
|
(14
|
)
|
|
|
|
(9
|
)
|
|
|
|
(14
|
)
|
Total Modified EBITDA
|
|
|
$
|
955
|
|
|
$
|
604
|
|
|
|
$
|
1,070
|
|
|
$
|
1,235
|
|
|
|
$
|
3,864
|
|
|
|
$
|
1,132
|
|
|
|
$
|
1,076
|
|
|
|
$
|
1,000
|
|
|
|
$
|
408
|
|
|
|
$
|
3,616
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast G&P
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and related costs
|
|
|
$
|
3
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
$
|
3
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
$
|
—
|
|
|
|
|
—
|
|
|
|
$
|
—
|
|
Share of impairment at equity-method investments
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
6
|
|
|
|
19
|
|
|
|
|
25
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
1
|
|
|
|
|
—
|
|
|
|
|
1
|
|
ACMP Merger and transition costs
|
|
|
|
2
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
2
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
Impairment of certain assets
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
121
|
|
|
|
|
—
|
|
|
|
|
121
|
|
Ad valorem obligation timing adjustment
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
7
|
|
|
|
|
—
|
|
|
|
|
7
|
|
Settlement charge from pension early payout program
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
7
|
|
|
|
|
7
|
|
Organizational realignment-related costs
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
3
|
|
|
|
|
3
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
2
|
|
|
|
|
—
|
|
|
|
|
4
|
|
Total Northeast G&P adjustments
|
|
|
|
5
|
|
|
|
—
|
|
|
|
|
6
|
|
|
|
22
|
|
|
|
|
33
|
|
|
|
|
1
|
|
|
|
|
1
|
|
|
|
|
131
|
|
|
|
|
7
|
|
|
|
|
140
|
|
Atlantic-Gulf
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potential rate refunds associated with rate case litigation
|
|
|
|
15
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
15
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
Severance and related costs
|
|
|
|
8
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
8
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
Constitution Pipeline project development costs
|
|
|
|
—
|
|
|
|
8
|
|
|
|
|
11
|
|
|
|
9
|
|
|
|
|
28
|
|
|
|
|
2
|
|
|
|
|
6
|
|
|
|
|
4
|
|
|
|
|
4
|
|
|
|
|
16
|
|
Settlement charge from pension early payout program
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
15
|
|
|
|
|
15
|
|
Regulatory charges resulting from Tax Reform
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
493
|
|
|
|
|
493
|
|
Share of regulatory charges resulting from Tax Reform for
equity-method investments
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
11
|
|
|
|
|
11
|
|
Organizational realignment-related costs
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
1
|
|
|
|
|
2
|
|
|
|
|
2
|
|
|
|
|
1
|
|
|
|
|
6
|
|
Gain on asset retirement
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
(11
|
)
|
|
|
|
(11
|
)
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(5
|
)
|
|
|
|
5
|
|
|
|
|
—
|
|
Total Atlantic-Gulf adjustments
|
|
|
|
23
|
|
|
|
8
|
|
|
|
|
11
|
|
|
|
(2
|
)
|
|
|
|
40
|
|
|
|
|
3
|
|
|
|
|
8
|
|
|
|
|
1
|
|
|
|
|
529
|
|
|
|
|
541
|
|
West
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated minimum volume commitments
|
|
|
|
60
|
|
|
|
64
|
|
|
|
|
70
|
|
|
|
(194
|
)
|
|
|
|
—
|
|
|
|
|
15
|
|
|
|
|
15
|
|
|
|
|
18
|
|
|
|
|
(48
|
)
|
|
|
|
—
|
|
Severance and related costs
|
|
|
|
10
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
3
|
|
|
|
|
13
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
ACMP Merger and transition costs
|
|
|
|
3
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
3
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
Impairment of certain assets
|
|
|
|
—
|
|
|
|
48
|
|
|
|
|
—
|
|
|
|
22
|
|
|
|
|
70
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
1,021
|
|
|
|
|
9
|
|
|
|
|
1,030
|
|
Settlement charge from pension early payout program
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
13
|
|
|
|
|
13
|
|
Regulatory charge associated with Tax Reform
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
220
|
|
|
|
|
220
|
|
Organizational realignment-related costs
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
21
|
|
|
|
|
21
|
|
|
|
|
2
|
|
|
|
|
3
|
|
|
|
|
2
|
|
|
|
|
1
|
|
|
|
|
8
|
|
Gains from contract settlements and terminations
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(13
|
)
|
|
|
|
(2
|
)
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(15
|
)
|
Total West adjustments
|
|
|
|
73
|
|
|
|
112
|
|
|
|
|
70
|
|
|
|
(148
|
)
|
|
|
|
107
|
|
|
|
|
4
|
|
|
|
|
16
|
|
|
|
|
1,041
|
|
|
|
|
195
|
|
|
|
|
1,256
|
|
NGL & Petchem Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of certain assets
|
|
|
|
—
|
|
|
|
341
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
341
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
Loss related to Canada disposition
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
32
|
|
|
|
2
|
|
|
|
|
34
|
|
|
|
|
(3
|
)
|
|
|
|
(1
|
)
|
|
|
|
4
|
|
|
|
|
4
|
|
|
|
|
4
|
|
Severance and related costs
|
|
|
|
4
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
4
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
Expenses associated with strategic asset monetizations
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
2
|
|
|
|
|
2
|
|
|
|
|
1
|
|
|
|
|
4
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
5
|
|
Geismar Incident adjustments
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
(7
|
)
|
|
|
|
(7
|
)
|
|
|
|
(9
|
)
|
|
|
|
2
|
|
|
|
|
8
|
|
|
|
|
(1
|
)
|
|
|
|
—
|
|
Gain on sale of Geismar Interest
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(1,095
|
)
|
|
|
|
—
|
|
|
|
|
(1,095
|
)
|
Gain on sale of RGP Splitter
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(12
|
)
|
|
|
|
|
|
|
—
|
|
|
|
|
(12
|
)
|
Accrual for loss contingency
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
9
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
9
|
|
Total NGL & Petchem Services adjustments
|
|
|
|
4
|
|
|
|
341
|
|
|
|
|
32
|
|
|
|
(3
|
)
|
|
|
|
374
|
|
|
|
|
(2
|
)
|
|
|
|
(7
|
)
|
|
|
|
(1,083
|
)
|
|
|
|
3
|
|
|
|
|
(1,089
|
)
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and related costs
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
9
|
|
|
|
|
9
|
|
|
|
|
9
|
|
|
|
|
4
|
|
|
|
|
5
|
|
|
|
|
4
|
|
|
|
|
22
|
|
ACMP Merger and transition costs
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
4
|
|
|
|
|
3
|
|
|
|
|
4
|
|
|
|
|
11
|
|
Expenses associated with Financial Repositioning
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
2
|
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
2
|
|
Gain on early retirement of debt
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(30
|
)
|
|
|
|
—
|
|
|
|
|
3
|
|
|
|
|
—
|
|
|
|
|
(27
|
)
|
Total Other adjustments
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
9
|
|
|
|
|
9
|
|
|
|
|
(21
|
)
|
|
|
|
10
|
|
|
|
|
11
|
|
|
|
|
8
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Adjustments
|
|
|
$
|
105
|
|
|
$
|
461
|
|
|
|
$
|
119
|
|
|
$
|
(122
|
)
|
|
|
$
|
563
|
|
|
|
$
|
(15
|
)
|
|
|
$
|
28
|
|
|
|
$
|
101
|
|
|
|
$
|
742
|
|
|
|
$
|
856
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast G&P
|
|
|
$
|
225
|
|
|
$
|
222
|
|
|
|
$
|
220
|
|
|
$
|
219
|
|
|
|
$
|
886
|
|
|
|
$
|
227
|
|
|
|
$
|
248
|
|
|
|
$
|
246
|
|
|
|
$
|
238
|
|
|
|
$
|
959
|
|
Atlantic-Gulf
|
|
|
|
405
|
|
|
|
368
|
|
|
|
|
434
|
|
|
|
454
|
|
|
|
|
1,661
|
|
|
|
|
453
|
|
|
|
|
462
|
|
|
|
|
431
|
|
|
|
|
433
|
|
|
|
|
1,779
|
|
West
|
|
|
|
400
|
|
|
|
424
|
|
|
|
|
433
|
|
|
|
394
|
|
|
|
|
1,651
|
|
|
|
|
389
|
|
|
|
|
372
|
|
|
|
|
426
|
|
|
|
|
481
|
|
|
|
|
1,668
|
|
NGL & Petchem Services
|
|
|
|
30
|
|
|
|
51
|
|
|
|
|
102
|
|
|
|
46
|
|
|
|
|
229
|
|
|
|
|
49
|
|
|
|
|
23
|
|
|
|
|
1
|
|
|
|
|
(1
|
)
|
|
|
|
72
|
|
Other
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
|
(1
|
)
|
|
|
|
(1
|
)
|
|
|
|
(3
|
)
|
|
|
|
(1
|
)
|
|
|
|
(6
|
)
|
Total Adjusted EBITDA
|
|
|
$
|
1,060
|
|
|
$
|
1,065
|
|
|
|
$
|
1,189
|
|
|
$
|
1,113
|
|
|
|
$
|
4,427
|
|
|
|
$
|
1,117
|
|
|
|
$
|
1,104
|
|
|
|
$
|
1,101
|
|
|
|
$
|
1,150
|
|
|
|
$
|
4,472
|
|
|
|
WPZ Reconciliation of "Net Income (Loss)" to "Modified EBITDA",
|
Non-GAAP "Adjusted EBITDA" and "Distributable Cash Flow"
|
|
|
|
2018 Guidance Range
|
(Dollars in billions, except coverage ratios)
|
|
|
Low
|
|
|
Mid
|
|
|
High
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
$
|
1.500
|
|
|
|
$
|
1.600
|
|
|
|
$
|
1.700
|
|
Provision (benefit) for income taxes
|
|
|
|
|
|
|
—
|
|
|
|
|
Interest expense
|
|
|
|
|
|
|
0.825
|
|
|
|
|
Equity (earnings) losses
|
|
|
|
|
|
|
(0.325
|
)
|
|
|
|
Proportional Modified EBITDA of equity-method investments
|
|
|
|
|
|
|
0.700
|
|
|
|
|
Depreciation and amortization expenses and accretion for asset
retirement obligations associated with nonregulated operations
|
|
|
|
|
|
|
1.750
|
|
|
|
|
Modified EBITDA
|
|
|
|
4.450
|
|
|
|
|
4.550
|
|
|
|
|
4.650
|
|
|
|
|
|
|
|
|
|
|
|
Total EBITDA adjustments
|
|
|
|
|
|
|
—
|
|
|
|
|
Adjusted EBITDA
|
|
|
|
4.450
|
|
|
|
|
4.550
|
|
|
|
|
4.650
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures (1)
|
|
|
|
(0.550
|
)
|
|
|
|
(0.500
|
)
|
|
|
|
(0.450
|
)
|
Interest expense (cash portion) (2)
|
|
|
|
|
|
|
(0.875
|
)
|
|
|
|
Income attributable to noncontrolling interests, cash taxes and other
|
|
|
|
|
|
|
(0.125
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow attributable to Partnership Operations
|
|
|
$
|
2.900
|
|
|
|
$
|
3.050
|
|
|
|
$
|
3.200
|
|
|
|
|
|
|
|
|
|
|
|
Total cash distributed
|
|
|
$
|
2.450
|
|
|
|
$
|
2.450
|
|
|
|
$
|
2.450
|
|
|
|
|
|
|
|
|
|
|
|
Cash Coverage Ratio (Distributable cash flow attributable to
Partnership Operations / Total cash distributed)
|
|
|
1.18x
|
|
|
1.24x
|
|
|
1.31x
|
|
|
|
|
|
|
|
|
|
|
(1) Includes proportionate share of maintenance capital expenditures
of equity investments.
|
(2) Includes proportionate share of interest expense of equity
investments.
|
|
View source version on businesswire.com: http://www.businesswire.com/news/home/20180214006285/en/
Copyright Business Wire 2018