- 2Q 2017 Net Income of $320 Million
- 2Q 2017 Adjusted EBITDA of $1.104
Billion, Up $39 Million
- 2Q 2017 Cash Distribution Coverage
Ratio of 1.22x
- Placed 3 Transco Expansions (Dalton
Expansion, Hillabee Phase 1 and Gulf Trace) Into Service So Far in
2017
- On July 6, 2017, Completed Sale of Its
Interests in Geismar Plant for $2.1 Billion in Cash; Entered into
Long-Term Supply and Transportation Agreements with Plant
Buyer
- Geismar Sale Proceeds Used to Pay Off
$850 Million Term Loan and Prefund a Portion of Growth Capex
Williams Partners L.P. (NYSE: WPZ) today announced its financial
results for the three and six months ended June 30, 2017.
Summary Financial Information 2Q YTD 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. 2017 2016 2017 2016
GAAP Measures Cash Flow from Operations $ 776 $ 742 $
1,507 $ 1,666 Net income (loss) $ 320 ($90 ) $ 954 ($40 ) Net
income (loss) per common unit $ 0.33 ($0.49 ) $ 1.00 ($0.74 )
Non-GAAP Measures (1) Adjusted EBITDA $ 1,104 $ 1,065 $
2,221 $ 2,125 DCF attributable to partnership operations $ 698 $
737 $ 1,450 $ 1,476 Cash distribution coverage ratio 1.22x 1.02x
1.27x 1.02x
(1) 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.
Second-Quarter 2017 Financial Results
Williams Partners reported unaudited second-quarter 2017 net
income attributable to controlling interests of $320 million, a
$410 million improvement over second-quarter 2016. The favorable
change was driven by a $452 million improvement in operating income
primarily reflecting a $394 million decrease in impairments of
certain assets and increased fee-based revenue from expansion
projects. The decrease in impairments includes the absence of a
second-quarter 2016, $341 million impairment charge associated with
the partnership’s now former Canadian business that was sold in
September 2016.
Year-to-date, Williams Partners reported unaudited net income of
$954 million, a $994 million improvement over the same period in
2016. The favorable change was driven by a $593 million improvement
in operating income primarily reflecting a $399 million decrease in
impairments of certain assets and increased fee-based revenue from
expansion projects. The decrease in impairments includes the
absence of the impairment charge referenced above. The improvement
in net income also reflects a gain of $269 million associated with
the disposition of certain equity-method investments in 2017 and
the absence of $112 million of impairments of equity-method
investments incurred in 2016.
Williams Partners reported second-quarter 2017 Adjusted EBITDA
of $1.104 billion, a $39 million increase over second-quarter 2016.
The improvement is due primarily to $18 million increased fee-based
revenues and a $24 million increase in proportional EBITDA of joint
ventures. Partially offsetting these increases were $22 million
lower olefins margins.
Year-to-date, Williams Partners reported Adjusted EBITDA of
$2.221 billion, an increase of $96 million over the same six-month
reporting period in 2016. The increase is due primarily to $36
million lower operating and maintenance (O&M) and selling,
general and administrative (SG&A) expenses, a $28 million
improvement in other income and expense, and a $29 million increase
in proportional EBITDA of joint ventures.
Distributable Cash Flow and Distributions
For second-quarter 2017, Williams Partners generated $698
million in distributable cash flow (DCF) attributable to
partnership operations, compared with $737 million in DCF
attributable to partnership operations for second-quarter 2016. DCF
for second-quarter 2017 has been reduced by $58 million for the
planned removal of non-cash deferred revenue amortization
associated with the fourth-quarter 2016 contract restructuring in
the Barnett Shale and Mid-Continent region. Also impacting the
unfavorable change were $25 million increased maintenance capital
expenditures and a $19 million increase in income attributable to
non-controlling interests. Partially offsetting the unfavorable
changes was the previously described improvement in the quarter’s
Adjusted EBITDA and a $29 million decrease in interest expense. For
second-quarter 2017, the cash distribution coverage ratio was
1.22x.
Year-to-date, Williams Partners generated $1.450 billion in DCF,
a decrease of $26 million over the same period in 2016. DCF for
2017 has been reduced by $116 million for the planned removal of
non-cash deferred revenue amortization associated with the
fourth-quarter 2016 contract restructuring in the Barnett Shale and
Mid-Continent region. Also impacting the unfavorable change were
$20 million increased maintenance capital expenditures and a $17
million increase in income attributable to non-controlling
interests. Partially offsetting the unfavorable changes were the
previously described improvement in year-to-date Adjusted EBITDA
and a $46 million decrease in interest expense. The cash
distribution coverage for the first six-month reporting period was
1.27x.
Williams Partners recently announced a regular quarterly cash
distribution of $0.60 per unit, payable Aug. 11, 2017, to its
common unitholders of record at the close of business on Aug. 4,
2017.
CEO Perspective
Alan Armstrong, chief executive officer of Williams Partners’
general partner, made the following comments:
“The second quarter demonstrated once again the long-term,
sustainable benefits of our focused strategy as we recognized
year-over-year growth in Adjusted EBITDA for the 15th consecutive
quarter. We met or exceeded business performance expectations in
all three remaining business units, offset by weaker than expected
performance at Geismar, which was impacted by a continuing outage
and lower margins. Strong performance in the Atlantic-Gulf, coupled
with expected growth for the balance of the year, gives us
confidence in achieving our prior guidance on Adjusted EBITDA and
DCF.
“We continue to deliver on project execution as planned for
2017. So far this year, we have successfully brought into service
three Transco expansion projects including the 1.2 Bcf/d Gulf Trace
project, the 0.8 Bcf/d Hillabee Phase 1 project, and just this
week, the 0.4 Bcf/d Dalton Expansion project. The line of sight to
future growth is evident as well as we are targeting second-half
2017 in-service dates for three more fully-contracted growth
projects including Virginia Southside II, New York Bay, and Garden
State Phase 1.
“In addition to strong year-over-year fee-based revenue growth
in the Atlantic-Gulf, we also saw gathered volumes in the West up
approximately 4 percent versus first-quarter 2017, adjusted for the
Marcellus-for-Permian transaction. While pipeline takeaway
constraints continue to impact volumes in the Northeast, we remain
well-positioned for volume growth as those constraints are lifted.
We’re also pleased our Susquehanna and Ohio River Systems delivered
year-over-year fee-based revenue growth. As we look ahead, around
97 percent of our gross margins will come from predictable
fee-based sources now that we have successfully completed the sale
of Geismar – reducing our commodity exposure and further
strengthening our natural gas-focused strategy.
“We continue to see benefits from the reorganization of our
operating areas and operational support functions such as safety
and procurement. Continuous improvement in safety performance and
project execution is another commitment that we are delivering on
at the mid-point of 2017 and will continue to focus on as we move
through the second half of the year.”
Business Segment Results
Effective, Jan. 1, 2017, Williams Partners implemented certain
changes in its reporting segments as part of an operational
realignment. As a result beginning with the reporting of
first-quarter 2017 financial results, Williams Partners operations
are comprised of the following reportable segments: Atlantic-Gulf,
West, Northeast G&P, and NGL & Petchem Services.
Williams Partners Modified and
Adjusted EBITDA Amounts in millions
2Q 2017 2Q
2016 YTD 2017 YTD 2016 Modified EBITDA
Adjust. Adjusted EBITDA
Modified EBITDA Adjust.
Adjusted EBITDA Modified EBITDA
Adjust. Adjusted EBITDA
Modified EBITDA Adjust.
Adjusted EBITDA Atlantic-Gulf $ 454 $ 8
$ 462 $ 360 $ 8 $ 368 $ 904 $ 11 $ 915 $ 742 $ 31 $
773 West 356 16 372 312 112 424 741 20 761 639 185 824 Northeast
G&P 247 1 248 222 - 222 473 2 475 442 5 447 NGL & Petchem
Services 30 (7 ) 23 (290 ) 341 51 81 (9 ) 72 (264 ) 345 81 Other
(11 ) 10 (1
) - -
- 9 (11 )
(2 ) - -
- Total
$ 1,076
$ 28 $
1,104 $ 604
$ 461 $ 1,065
$ 2,208 $ 13
$ 2,221 $
1,559 $ 566
$ 2,125 Definitions of modified
EBITDA and adjusted EBITDA and schedules reconciling these measures
to net income are included in this news release.
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 under development,
and a 60 percent equity-method investment in Discovery.
The Atlantic-Gulf segment reported Modified EBITDA of $454
million for second-quarter 2017, compared with $360 million for
second-quarter 2016. Adjusted EBITDA increased by $94 million to
$462 million for the same reporting period. The increase in both
measures was driven primarily by $88 million increased fee-based
revenues due primarily to higher volumes from Gulfstar One and
Transco expansion projects placed in service, as well as higher
proportional EBITDA from joint ventures related to an $11 million
increase from Discovery. Partially offsetting the favorable results
were $14 million in increased O&M expenses due primarily to
higher costs associated with Transco’s integrity and pipeline
maintenance program.
Year-to-date, the Atlantic-Gulf segment reported Modified EBITDA
of $904 million, an increase of $162 million over the same
six-month period in 2016. Adjusted EBITDA increased $142 million to
$915 million. The drivers for the increase in both measures are an
improvement in fee-based revenues due primarily to higher volumes
from Gulfstar One and Transco expansion projects placed in service,
$18 million higher proportional EBITDA from joint ventures
primarily from Discovery, and $13 million higher commodity margins.
Partially offsetting these improvements were increased O&M
expenses due primarily to higher costs associated with Transco’s
integrity and pipeline maintenance program and the segment’s
offshore business.
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, 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 $356 million for
second-quarter 2017, compared with $312 million for second-quarter
2016. Adjusted EBITDA decreased by $52 million to $372 million. The
increase in Modified EBITDA was driven primarily by the absence of
$48 million of impairments that impacted second-quarter 2016, which
are excluded from Adjusted EBITDA. The decrease in Adjusted EBITDA
was due primarily to $51 million lower fee-based revenues,
including $18 million lower fee-based revenues in the Barnett from
lower volumes and contract changes that occurred during 2016.
Revenues in the Niobrara decreased by $7 million due to a change in
revenue recognition timing resulting from contract restructuring.
The unfavorable change in Adjusted EBITDA was also impacted by $10
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. Volume
decreases in other areas also contributed to the unfavorable
change. Partially offsetting the decrease was a $14 million decline
in O&M and SG&A expenses.
Year-to-date, the West segment reported Modified EBITDA of $741
million, an increase of $102 million over the same six-month period
in 2016. Adjusted EBITDA decreased by $63 million to $761 million.
The increase in Modified EBITDA was driven primarily by a $65
million improvement in other income and expense, which included the
absence of the impairments that impacted second-quarter 2016 and
are excluded from Adjusted EBITDA. The favorable change also
reflects $46 million in reduced O&M and SG&A expenses, $8
million of which are excluded from the Adjusted EBITDA measure. The
decrease in Adjusted EBITDA was driven primarily by $108 million
lower fee-based revenues, including $44 million lower fee-based
revenues in the Barnett from lower volumes and contract changes
that occurred during 2016. Revenues in the Niobrara decreased by
$17 million due to a change in revenue recognition timing resulting
from contract restructuring. The unfavorable change in Adjusted
EBITDA was also impacted by $10 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. Volume decreases in other areas also
contributed to the unfavorable change. Partially offsetting the
decreases were the reduced O&M and SG&A expenses described
above and $17 million in improved commodity margins.
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 Utica East Ohio Midstream
(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 $247
million for second-quarter 2017, compared with $222 million for
second-quarter 2016. Adjusted EBITDA increased by $26 million to
$248 million. The improvement in both measures was driven primarily
by a $22 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.
Year-to-date, the Northeast G&P segment reported Modified
EBITDA of $473 million, an increase of $31 million over the same
six-month period in 2016. Adjusted EBITDA increased by $28 million
to $475 million. The improvement in both measures was driven
primarily by a $21 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.
The NGL & Petchem Services segment reported Modified EBITDA
of $30 million for second-quarter 2017, compared with ($290)
million for second-quarter 2016. Adjusted EBITDA decreased by $28
million to $23 million. The favorable change in Modified EBITDA was
driven primarily by the absence of a second-quarter 2016, $341
million impairment charge associated with Williams Partners’ now
former Canadian business that was sold in September 2016. Adjusted
EBITDA was unfavorably impacted by a $22 million decrease in
olefins margins due primarily to lower volumes at the Geismar
olefins plant due to an unexpected power outage at the plant that
resulted in the facility being offline from March 12 until
restarting on April 18, 2017. Lower volumes at the RGP Splitter in
connection with its sale on June 30 also contributed to the
unfavorable change. The quarter’s unfavorable change in Adjusted
EBITDA also reflects a $19 million decrease in fee-based revenues
due primarily to the third-quarter 2016 sale of the partnership’s
now former Canadian business. Partially offsetting these decreases
was a $15 million reduction in O&M and SG&A expenses due
primarily to the September 2016 sale of the partnership’s now
former Canadian business.
Year-to-date, the NGL & Petchem Services segment reported
Modified EBITDA of $81 million, an improvement of $345 million over
the same six-month period in 2016. Adjusted EBITDA decreased $9
million to $72 million. The favorable change in Modified EBITDA was
driven primarily by the absence of a second-quarter 2016, $341
million impairment charge associated with Williams Partners’ now
former Canadian business that was sold in September 2016. Adjusted
EBITDA was unfavorably impacted by a $24 million decrease in
fee-based revenues and a $22 million decrease in olefins margins
due primarily to lower volumes. The Geismar olefins plant had lower
volumes due to the previously described power outage. The segment’s
lower fee-based revenues and olefins margins also reflect the sale
of the partnership’s now former Canadian business in September
2016. Partially offsetting these decreases was a $28 million
reduction in O&M and SG&A expenses due primarily to the
third-quarter 2016 sale of Williams Partners’ now former Canadian
business.
Williams Partners does not expect significant future operating
results from this segment; however, as a result of the sale of its
interest in the Geismar olefins facility referenced above, the
partnership expects to record a gain of approximately $1.1 billion
in the third quarter of 2017.
Atlantic Sunrise Update
Williams Partners received notice to proceed on the mainline
portion of the project, and construction activities are underway.
In third-quarter 2017, the partnership expects to begin early
mainline service and to receive final permits on the greenfield
portion of the project. Williams Partners continues to target
mid-2018 for the project’s full in-service date.
Guidance
The Guidance previously provided at our Analyst Day event on May
11, 2017, remains unchanged.
Williams Partners’ Second-Quarter 2017 Materials to be Posted
Shortly; Q&A Webcast Scheduled for Tomorrow
Williams Partners’ second-quarter 2017 financial results package
will be posted shortly at www.williams.com. The materials will
include the analyst package.
Williams Partners and Williams will host a joint Q&A live
webcast on Thursday, Aug. 3 at 9:30 a.m. Eastern Daylight Time
(8:30 a.m. Central Daylight Time). A limited number of phone lines
will be available at (877) 419-6594. International callers should
dial (719) 325-4888. The conference ID is 9171330. 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-Q
The partnership plans to file its second-quarter 2017 Form 10-Q
with the Securities and Exchange Commission (SEC) this week. Once
filed, the document will be available on both the SEC and Williams
Partners websites.
Definitions of Non-GAAP Measures
This news release 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,
regulations, the regulatory environment, environmental liabilities,
and litigation, as well as our ability to obtain permits 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 our risk factors in addition to the other information
provided herein. If any of the risks to which we are exposed 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 Year
Williams Partners L.P.
Reconciliation of GAAP "Net Income (Loss)" to Non-GAAP "Modified
EBITDA", "Adjusted EBITDA", and "Distributable cash flow”
Net income (loss) $ 79 $ (77 ) $ 351 $ 166 $ 519 $ 660 $ 348 $
1,008 Provision (benefit) for income taxes 1 (80 ) (6 ) 5 (80 ) 3 1
4 Interest expense 229 231 229 227 916 214 205 419 Equity
(earnings) losses (97 ) (101 ) (104 ) (95 ) (397 ) (107 ) (125 )
(232 ) Impairment of equity-method investments 112 — — 318 430 — —
— Other investing (income) loss — (1 ) (28 ) — (29 ) (271 ) (2 )
(273 ) Proportional Modified EBITDA of equity-method investments
189 191 194 180 754 194 215 409 Depreciation and amortization
expenses 435 432 426 427 1,720 433 423 856 Accretion for asset
retirement obligations associated with nonregulated operations
7 9
8 7 31
6 11
17 Modified EBITDA 955 604 1,070 1,235 3,864 1,132
1,076 2,208 Adjustments Estimated minimum volume commitments
60 64 70 (194 ) — 15 15 30 Severance and related costs 25 — — 12 37
9 4 13 Potential rate refunds associated with rate case litigation
15 — — — 15 — — — Merger and transition related expenses 5 — — — 5
— 4 4 Constitution Pipeline project development costs — 8 11 9 28 2
6 8 Share of impairment at equity-method investment — — 6 19 25 — —
— Geismar Incident adjustment for insurance and timing — — — (7 )
(7 ) (9 ) 2 (7 ) Impairment of certain assets — 389 — 22 411 — — —
Organizational realignment-related costs — — — 24 24 4 6 10 Loss
related to Canada disposition — — 32 2 34 (3 ) (1 ) (4 ) Gain on
asset retirement — — — (11 ) (11 ) — — — Gains from contract
settlements and terminations — — — — — (13 ) (2 ) (15 ) Accrual for
loss contingency — — — — — 9 — 9 Gain on early retirement of debt —
— — — — (30 ) — (30 ) 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 13 Adjusted
EBITDA 1,060 1,065 1,189 1,113 4,427 1,117 1,104 2,221
Maintenance capital expenditures (1) (58 ) (75 ) (121 ) (147 ) (401
) (53 ) (100 ) (153 ) Interest expense (cash portion) (2) (241 )
(245 ) (244 ) (239 ) (969 ) (224 ) (216 ) (440 ) Cash taxes — — —
(3 ) (3 ) (5 ) (1 ) (6 ) Income attributable to noncontrolling
interests (3) (29 ) (13 ) (31 ) (27 ) (100 ) (27 ) (32 ) (59 ) WPZ
restricted stock unit non-cash compensation 7 5 2 2 16 2 1 3
Amortization of deferred revenue associated with certain 2016
contract restructurings — —
— —
— (58 ) (58
) (116 ) Distributable cash flow
attributable to Partnership Operations (4) 739
737 795
699 2,970
752 698
1,450 Total cash distributed (5) $ 725 $ 725 $ 734 $
762 $ 2,946 $ 567 $ 574 $ 1,141
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 1.27
Net income (loss) divided by Total cash distributed
0.11 (0.11 )
0.48 0.22
0.18 1.16 0.61
0.88 (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 Non-GAAP “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 Year
Modified EBITDA: Northeast
G&P $ 220 $ 222 $ 214 $ 197 $ 853 $ 226 $ 247 $ 473
Atlantic-Gulf 382 360 423 456 1,621 450 454 904 West 327 312 363
542 1,544 385 356 741 NGL & Petchem Services 26 (290 ) 70 49
(145 ) 51 30 81 Other — —
— (9 ) (9 )
20 (11 ) 9
Total Modified EBITDA $ 955
$ 604 $
1,070 $ 1,235
$ 3,864 $ 1,132
$ 1,076 $
2,208 Adjustments:
Northeast
G&P
Severance and related costs $ 3 $ — $ — $ — $ 3 $ — $ — $ — Share
of impairment at equity-method investments — — 6 19 25 — — — ACMP
Merger and transition costs 2 — — — 2 — — — Organizational
realignment-related costs — —
— 3
3 1 1
2 Total Northeast G&P adjustments 5
— 6 22 33 1 1 2
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 8 Organizational
realignment-related costs — — — — — 1 2 3 Gain on asset retirement
— — —
(11 ) (11 ) —
— —
Total Atlantic-Gulf adjustments 23 8 11 (2 ) 40 3 8 11
West
Estimated minimum volume commitments 60 64 70 (194 ) — 15 15 30
Severance and related costs 10 — — 3 13 — — — ACMP Merger and
transition costs 3 — — — 3 — — — Impairment of certain assets — 48
— 22 70 — — — Organizational realignment-related costs — — — 21 21
2 3 5
Gains from contract settlements and
terminations
— — —
— —
(13 ) (2 ) (15 ) Total
West adjustments 73 112 70 (148 ) 107 4 16 20
NGL & Petchem
Services
Impairment of certain assets — 341 — — 341 — — — Loss related to
Canada disposition — — 32 2 34 (3 ) (1 ) (4 ) Severance and related
costs 4 — — — 4 — — — Expenses associated with strategic asset
monetizations — — — 2 2 1 4 5 Geismar Incident adjustment for
insurance and timing — — — (7 ) (7 ) (9 ) 2 (7 ) 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 ) (9 )
Other
Severance and related costs — — — 9 9 9 4 13 ACMP Merger-related
expenses — — — — — — 4 4 Expenses associated with Financial
Repositioning — — — — — — 2 2 Gain on early retirement of debt
— — —
— —
(30 ) — (30 )
Total Other adjustments — — — 9 9 (21 ) 10 (11 )
Total Adjustments $ 105 $
461 $ 119
$ (122 ) $ 563
$ (15 ) $
28 $ 13
Adjusted EBITDA: Northeast G&P $ 225 $ 222 $ 220 $ 219 $
886 $ 227 $ 248 $ 475 Atlantic-Gulf 405 368 434 454 1,661 453 462
915 West 400 424 433 394 1,651 389 372 761 NGL & Petchem
Services 30 51 102 46 229 49 23 72 Other —
— — —
— (1 )
(1 ) (2 )
Total Adjusted EBITDA
$ 1,060 $ 1,065
$ 1,189 $
1,113 $ 4,427
$ 1,117 $ 1,104
$ 2,221
View source
version on businesswire.com: http://www.businesswire.com/news/home/20170802006246/en/
Williams Partners L.P.Media Contact:Keith Isbell,
918-573-7308orInvestor Contact:Brett Krieg, 918-573-4614
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