- 3Q 2017 Net Income of $259 Million
- 3Q 2017 Adjusted EBITDA of $1.101
Billion
- 3Q 2017 Cash Distribution Coverage
Ratio of 1.17x; 1.24x Year-to-Date
- Placed 4 Transco Expansions (Gulf
Trace, Hillabee Phase 1, Dalton Expansion, and New York Bay
Expansion) Into Service to Date in 2017; Design Capacity Up
25%
- Williams Partners Continues to
Significantly Improve Credit Profile; Net Debt (Long-term Debt Less
Cash) Reduced by $3 Billion Since Jan. 1, 2017
- Achieved Key Milestones for Atlantic
Sunrise Project
Williams Partners L.P. (NYSE: WPZ) today announced its financial
results for the three and nine months ended Sept. 30, 2017.
Summary Financial Information 3Q
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 $ 596 $ 685 $ 2,103 $ 2,351 Net income (loss) $ 259 $
326 $ 1,213 $ 286 Net income (loss) per common unit $ 0.27 $ 0.42 $
1.26 ($0.32 ) Non-GAAP Measures (1) Adjusted EBITDA $ 1,101
$ 1,189 $ 3,322 $ 3,314 DCF attributable to partnership operations
$ 669 $ 795 $ 2,119 $ 2,271 Cash distribution coverage ratio 1.17 x
1.08 x 1.24 x 1.04 x
(1) Adjusted EBITDA, distributable cash
flow (DCF) and cash coverage ratio are non-GAAP measures.
Reconciliations to the most relevant measures included in GAAP are
attached to this news release.
Third-Quarter 2017 Financial Results
Williams Partners reported unaudited third-quarter 2017 net
income attributable to controlling interests of $259 million, a $67
million decrease from third-quarter 2016. The unfavorable change
was driven primarily by the absence of results associated with the
Geismar olefins facility, which was sold July 6, 2017, and the
partnership's former Canadian business, which was sold in September
2016. In addition, results were negatively impacted by impairments
of certain assets, largely offset by the gain related to the sale
of the Geismar facility.
Year-to-date, Williams Partners reported unaudited net income
attributable to controlling interests of $1.213 billion, a $927
million improvement over the same nine-month reporting period in
2016. The favorable change was driven primarily by increased
fee-based revenues from expansion projects, and gains on the sale
of assets and equity investments. These favorable results were
partially offset by higher impairment losses on assets between the
periods and the decrease related to the previously mentioned sales
of the Geismar olefins facility and the partnership's former
Canadian operations.
Williams Partners reported third-quarter 2017 Adjusted EBITDA of
$1.101 billion, an $88 million decrease from third-quarter 2016.
The unfavorable change was driven primarily by the absence of $101
million of Adjusted EBITDA contribution from the NGL & Petchem
Services segment associated with the previously described assets
sold. Williams Partners' current businesses increased Adjusted
EBITDA by approximately $13 million including an unfavorable impact
of approximately $8 million from Hurricanes Harvey and Irma.
Year-to-date, Williams Partners reported Adjusted EBITDA of
$3.322 billion, an $8 million increase over the corresponding
nine-month reporting period in 2016. The comparison includes an
approximately $110 million decrease from the NGL & Petchem
Services segment associated with the previously described assets
that were sold. Williams Partners' current businesses increased
Adjusted EBITDA by approximately $118 million during the period.
Favorable results included increased fee-based revenues, improved
commodity margins, lower selling, general and administrative
(SG&A) expenses and increased proportional EBITDA from joint
ventures. Partially offsetting the increases were higher operating
and maintenance (O&M) expenses.
Distributable Cash Flow and Distributions
For third-quarter 2017, Williams Partners generated $669 million
in distributable cash flow (DCF) attributable to partnership
operations, compared with $795 million in DCF attributable to
partnership operations for third-quarter 2016. DCF was unfavorably
impacted by the change in Adjusted EBITDA described above. DCF for
third-quarter 2017 was also reduced by $59 million for the removal
of non-cash deferred revenue amortization associated with the
fourth-quarter 2016 contract restructurings in the Barnett Shale
and Mid-Continent region. Partially offsetting the unfavorable
change was a $37 million decrease in interest expense. For
third-quarter 2017, the cash distribution coverage ratio was
1.17x.
Year-to-date, Williams Partners generated $2.119 billion in DCF
attributable to partnership operations, an unfavorable change of
$152 million compared with the same period in 2016. DCF for 2017
was reduced by $175 million for the non-cash deferred revenue
amortization associated with the previously described contract
restructurings. Also contributing to the unfavorable change was a
$35 million increase in maintenance capital expenditures. Partially
offsetting the unfavorable change was an $83 million decrease in
interest expense. The cash distribution coverage for the nine-month
reporting period was 1.24x.
Williams Partners recently announced a regular quarterly cash
distribution of $0.60 per unit, payable Nov. 10, 2017, to its
common unitholders of record at the close of business on Nov. 3,
2017.
CEO Perspective
Alan Armstrong, chief executive officer of Williams Partners’
general partner, made the following comments:
“The large-scale, competitive positions we've established
continue to generate long-term value as evidenced once again this
quarter as we maintained our strong results with year-to-date
Adjusted EBITDA comparable to 2016 results despite the impact of
two hurricanes and the sale of over $3 billion in assets. We've
substantially reduced our direct exposure to commodities and, as a
result, our current businesses' steady growth is being driven by
consistent fee-based revenue growth.
“Our strategic focus on natural gas volumes continues to deliver
results. So far in 2017, we've placed four of our 'Big 5' Transco
expansion projects into service including Gulf Trace, Hillabee
Phase 1, Dalton Expansion and New York Bay Expansion with the fifth
of the 'Big 5' expansions - the Virginia Southside II project -
expected to be placed in service during fourth-quarter 2017. The
incremental capacity from the fully-contracted Transco expansion
projects going in service so far this year reflects a 25 percent
increase in Transco’s design capacity. And, year-to-date, Transco's
transportation revenues have increased $74 million, a 7 percent
increase over last year.
“Our existing asset footprint and the efficient incremental
expansions available to us have also been highlighted in our
Northeast G&P and West segments. Our recently announced
agreement to expand our services in the Northeast for our valued
customer, Southwestern Energy, showcases how well-positioned our
Northeast G&P segment is to serve the growing gas production in
the Marcellus and Utica. We are also positioned to capture growth
in the Haynesville where in August, we completed the Springridge
South plant expansion, and in Wyoming where we are able to bring
more volumes onto our Wamsutter system after placing our Chain Lake
compressor station into service in October to meet the growing
demand of a customer.
“I’m also extremely pleased that even as we continue to deliver
on our growth strategy by successfully executing on expansion
projects across our operational map, we have strengthened our
balance sheet and credit profile, significantly reducing our debt
and continued to lower expenses. Year-to-date in 2017, total
adjusted SG&A expenses have been reduced by about $40 million
when compared to the same period in 2016.”
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
were 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.
Amounts in millions
3Q 2017 3Q
2016 YTD 2017 YTD
2016
ModifiedEBITDA
Adjust.
AdjustedEBITDA
ModifiedEBITDA Adjust.
Adjusted
EBITDA
Modified
EBITDA
Adjust. Adjusted
EBITDA
Modified
EBITDA
Adjust. Adjusted
EBITDA
Atlantic -Gulf $ 430 $ 1 $ 431 $ 423 $ 11
$ 434 $ 1,334 $ 12 $ 1,346 $ 1,165 $ 42
$ 1,207 West (615 ) 1,041 426 363 70 433 126 1,061 1,187
1,002 255 1,257 Northeast G&P 115 131 246 214 6 220 588 133 721
656 11 667 NGL & Petchem Services 1,084 (1,083 ) 1 70 32 102
1,165 (1,092 ) 73 (194 ) 377 183 Other (14 )
11 (3 ) — —
— (5 ) — (5 ) —
— — Total $ 1,000
$ 101 $ 1,101 $ 1,070 $ 119 $
1,189 $ 3,208 $ 114 $ 3,322 $
2,629 $ 685 $ 3,314 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 $430
million for third-quarter 2017, compared with $423 million for
third-quarter 2016. Adjusted EBITDA decreased by $3 million to $431
million for the same time period. The increase in Modified EBITDA
was driven primarily by $46 million increased fee-based revenues
from Transco expansion projects brought online. Partially
offsetting the increase were $29 million increased O&M expenses
primarily associated with Transco's integrity and pipeline
maintenance programs. Proportional EBITDA from joint ventures
decreased by $11 million. The total unfavorable impact to
Atlantic-Gulf in third-quarter 2017 related to hurricanes was over
$6 million.
Year-to-date, Atlantic-Gulf reported Modified EBITDA of $1.334
billion, an increase of $169 million over the same nine-month
reporting period in 2016. Adjusted EBITDA increased $139 million to
$1.346 billion. Fee-based revenues increased $199 million due
primarily to higher volumes from Gulfstar One and Transco expansion
projects placed in service. Partially offsetting these improvements
were $56 million increased O&M expenses due primarily to higher
costs associated with Transco’s integrity and pipeline maintenance
programs, the segment’s offshore business, and costs associated
with several of Transco's expansion projects.
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 disposal 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 ($615) million for
third-quarter 2017, compared with $363 million for third-quarter
2016. Adjusted EBITDA decreased by $7 million to $426 million. The
unfavorable change in Modified EBITDA was driven primarily by a
$1.019 billion impairment of certain gathering operations in the
Mid-Continent region. The unfavorable change also includes $11
million in 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. Partially
offsetting these decreases were $19 million higher fee-based
revenues, a $21 million increase in commodity margins and a $12
million decline in O&M and SG&A expenses. Adjusted EBITDA
excludes the previously mentioned impairment charge and is further
adjusted for estimated minimum volume commitments. As a result,
Adjusted EBITDA reflects $33 million of lower fee-based revenues.
The West segment also experienced unfavorable impacts from
Hurricane Harvey of more than $1 million during third-quarter
2017.
Year-to-date, the West segment reported Modified EBITDA of $126
million, a decrease of $876 million from the same nine-month period
in 2016. Adjusted EBITDA decreased by $70 million to $1.187
billion. The unfavorable change in Modified EBITDA reflected the
impairment in the Mid-Continent region described in the above
paragraph. The unfavorable change also includes $21 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. Partially offsetting
the decreases were $59 million in reduced O&M and SG&A
expenses and $38 million in improved commodity margins. Revenues
reflect an increase from the amortization of deferred revenue from
2016 contract restructurings largely offset by lower rates
associated with those restructurings and lower volumes driven by
natural declines. Adjusted EBITDA excludes the previously mentioned
impairment charge and is further adjusted for estimated minimum
volume commitments. As a result, Adjusted EBITDA reflects $141
million of lower fee-based revenues.
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 $115
million for third-quarter 2017, compared with $214 million for
third-quarter 2016. Adjusted EBITDA increased by $26 million to
$246 million. The unfavorable change in Modified EBITDA reflected a
$115 million impairment of certain gathering operations in the
Marcellus South. This impairment charge is excluded from Adjusted
EBITDA. The current year benefited from a $30 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
that offset decreases in the Utica.
Year-to-date, the Northeast G&P segment reported Modified
EBITDA of $588 million, a decrease of $68 million over the
corresponding nine-month period in 2016. Adjusted EBITDA increased
by $54 million to $721 million. The unfavorable change in Modified
EBITDA reflected the impairment in the Marcellus South region
described in the above paragraph. This impairment charge is
excluded from Adjusted EBITDA. The current year benefited from a
$51 million increase in proportional EBITDA of joint ventures due
largely to the previously described increase in ownership in two
Marcellus shale gathering systems. 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.
The NGL & Petchem Services segment reported Modified EBITDA
of $1.084 billion for third-quarter 2017, compared with $70 million
for third-quarter 2016. Adjusted EBITDA decreased by $101 million
to $1 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. This gain is excluded from Adjusted EBITDA. The current year
was also impacted by the absence of EBITDA associated with assets
recently sold by the partnership as described in the above
paragraph.
Year-to-date, the NGL & Petchem Services segment reported
Modified EBITDA of $1.165 billion, an improvement of $1.359 billion
over the same nine-month reporting period in 2016. Adjusted EBITDA
decreased $110 million to $73 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 recently sold by the partnership.
Atlantic Sunrise Update
On Sept. 18, 2017 Williams Partners reported that construction
is now underway in Pennsylvania on the greenfield portion of the
Atlantic Sunrise pipeline project - an expansion of the existing
Transco natural gas pipeline to connect abundant Marcellus gas
supplies with markets in the Mid-Atlantic and Southeastern U.S. The
partnership anticipates pipeline and compressor station
construction to last approximately 10 months, weather permitting.
Additionally, Williams Partners also placed a portion of the
project into early service on Sept. 1, 2017, providing 400,000
dth/day of firm transportation service on Transco's existing
mainline facilities to various delivery points as far south as
Choctaw County, Alabama. The partial service milestone is the
result of recently completed modifications to existing Transco
facilities in Virginia and Maryland designed to further accommodate
bi-directional flow on the existing Transco pipeline system.
Additional Notable Recent Accomplishments
On Oct. 12, 2017, Williams Partners announced the execution of
agreements with Southwestern Energy Company (NYSE: SWN)
(“Southwestern”) to expand its services to Southwestern in the
Appalachian Basin of West Virginia where Williams Partners has
established a strong operational footprint. The agreements call for
Williams Partners to deliver gas processing, fractionation, and
liquids handling services in Southwestern’s Wet Gas Acreage in the
Marcellus and Upper Devonian Shale along with gas gathering
services for Southwestern in its South Utica Dry Gas Acreage.
Williams Partners will provide Southwestern with 660 million cubic
feet per day (MMcf/d) of processing capacity to serve a
135,000-acre dedication in Southwestern’s Wet Gas Acreage in the
Marcellus and Upper Devonian Shale in Marshall and Wetzel counties
in West Virginia. As a result of this agreement, Williams Partners
expects to further build out its Oak Grove processing facility for
Southwestern’s expanding production of wet gas. The Oak Grove
processing facility has the ability to expand by an additional 1.8
Bcf/d of gas processing capacity.
On Oct. 9, 2017, Williams Partners announced that it has placed
into service an expansion of its Transco pipeline system to
increase natural gas delivery capacity to New York City by 115,000
dekatherms per day in time for the 2017/2018 heating
season. The New York Bay Expansion provides additional firm
transportation capacity for much-needed incremental natural gas
supplies to National Grid, the largest distributor of natural gas
in the northeastern U.S. The company provides service to 1.8
million customers in Brooklyn, Queens, Staten Island and Long
Island. The New York Bay Expansion is the fourth of Williams
Partners’ projected five fully-contracted Transco expansion
projects to be placed into service this year, combining with Gulf
Trace, Hillabee Phase 1 and the Dalton Expansion to add more than
2.5 million dekatherms per day capacity to the Transco pipeline
system so far in 2017. The partnership continues to target a
fourth-quarter 2017 in-service date for its fifth Transco expansion
this year - the Virginia Southside II project.
Williams Partners' Credit Profile Improvement including Debt
Reduction Update
The partnership continued to strengthen its balance sheet and
credit profile during the quarter with nearly $2.1 billion of debt
reduction. As of the end of third-quarter 2017, the
partnership had total debt of $16.5 billion. Year-to-date, cash and
cash equivalents increased by $1.02 billion to $1.17 billion, which
the partnership intends to use primarily to fund growth capital
expenditures and long-term investments.
Guidance
The Guidance previously provided at our Analyst Day event on May
11, 2017, remains unchanged. The partnership plans to announce its
2018 Guidance as part of the release of its fourth-quarter 2017
financial results.
Williams Partners’ Third-Quarter 2017 Materials to be Posted
Shortly; Q&A Webcast Scheduled for Tomorrow
Williams Partners’ third-quarter 2017 financial results package
will be posted shortly at www.williams.com. Note: the analyst package is
included at the back of this news release.
Williams Partners and Williams will host a joint Q&A live
webcast on Thursday, Nov. 2 at 9:30 a.m. Eastern Time (8:30 a.m.
Central Time). A limited number of phone lines will be available at
(877) 830-2641. International callers should dial (785) 424-1809.
The conference ID is 8089866. 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 third-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 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.
Non-GAAP Reconciliations, Financial Highlights,
and Operating Statistics (UNAUDITED) Final
September 30, 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
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 $ 1,292 Provision (benefit) for income taxes 1 (80 ) (6
) 5 (80 ) 3 1 (1 ) 3 Interest expense 229 231 229 227 916 214 205
202 621 Equity (earnings) losses (97 ) (101 ) (104 ) (95 ) (397 )
(107 ) (125 ) (115 ) (347 ) Impairment of equity-method investments
112 — — 318 430 — — — — Other investing (income) loss — (1 ) (28 )
— (29 ) (271 ) (2 ) (4 ) (277 ) Proportional Modified EBITDA of
equity-method investments 189 191 194 180 754 194 215 202 611
Depreciation and amortization expenses 435 432 426 427 1,720 433
423 424 1,280 Accretion for asset retirement obligations associated
with nonregulated operations 7 9
8 7 31 6 11
8 25 Modified EBITDA 955 604 1,070
1,235 3,864 1,132 1,076 1,000 3,208 Adjustments Estimated
minimum volume commitments 60 64 70 (194 ) — 15 15 18 48 Severance
and related costs 25 — — 12 37 9 4 5 18 Potential rate refunds
associated with rate case litigation 15 — — — 15 — — — — ACMP
Merger and transition costs 5 — — — 5 — 4 3 7 Constitution Pipeline
project development costs — 8 11 9 28 2 6 4 12 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 1,142 Ad valorem obligation timing
adjustment — — — — — — — 7 7 Organizational realignment-related
costs — — — 24 24 4 6 6 16 Loss related to Canada disposition — —
32 2 34 (3 ) (1 ) 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
114 Adjusted EBITDA 1,060 1,065 1,189 1,113
4,427 1,117 1,104 1,101 3,322 Maintenance capital
expenditures (1) (58 ) (75 ) (121 ) (147 ) (401 ) (53 ) (100 ) (136
) (289 ) Interest expense (cash portion) (2) (241 ) (245 ) (244 )
(239 ) (969 ) (224 ) (216 ) (207 ) (647 ) Cash taxes — — — (3 ) (3
) (5 ) (1 ) (4 ) (10 ) Income attributable to noncontrolling
interests (3) (29 ) (13 ) (31 ) (27 ) (100 ) (27 ) (32 ) (27 ) (86
) WPZ restricted stock unit non-cash compensation 7 5 2 2 16 2 1 1
4 Amortization of deferred revenue associated with certain 2016
contract restructurings — — —
— — (58 ) (58 )
(59 ) (175 ) Distributable cash flow attributable to
Partnership Operations (4) 739 737
795 699 2,970 752
698 669 2,119
Total cash distributed (5) $ 725 $ 725 $ 734 $ 762 $ 2,946 $ 567 $
574 $ 574 $ 1,715
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 1.24 Net income
(loss) divided by Total cash distributed 0.11
(0.11 ) 0.48 0.22 0.18
1.16 0.61 0.49 0.75
(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 Year
Modified
EBITDA:
Northeast G&P $ 220 $ 222 $ 214 $ 197 $ 853 $ 226 $ 247 $ 115 $
588 Atlantic-Gulf 382 360 423 456 1,621 450 454 430 1,334 West 327
312 363 542 1,544 385 356 (615 ) 126 NGL & Petchem Services 26
(290 ) 70 49 (145 ) 51 30 1,084 1,165 Other —
— — (9 ) (9 )
20 (11 ) (14 )
(5 )
Total Modified EBITDA $ 955
$ 604 $ 1,070
$ 1,235 $ 3,864
$ 1,132 $ 1,076
$ 1,000 $ 3,208
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 Organizational realignment-related
costs — — —
3 3 1 1
2 4 Total
Northeast G&P adjustments 5 — 6 22 33 1 1 131 133
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
12 Organizational realignment-related costs — — — — — 1 2 2 5 Gain
on asset retirement — — —
(11 ) (11 ) —
— (5 ) (5 ) Total
Atlantic-Gulf adjustments 23 8 11 (2 ) 40 3 8 1 12
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 1,021 Organizational realignment-related costs
— — — 21 21 2 3 2 7 Gains from contract settlements and
terminations — — —
— — (13 )
(2 ) — (15 ) Total West
adjustments 73 112 70 (148 ) 107 4 16 1,041 1,061
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 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 ) (1,092 )
Other
Severance and related costs — — — 9 9 9 4 5 18 ACMP Merger and
transition costs — — — — — — 4 3 7 Expenses associated with
Financial Repositioning — — — — — — 2 — 2 Gain on early retirement
of debt — — —
— — (30 ) —
3 (27 ) Total Other
adjustments — — — 9 9 (21 ) 10 11 —
Total Adjustments $ 105
$ 461 $ 119
$ (122 ) $ 563
$ (15 ) $ 28
$ 101 $ 114
Adjusted EBITDA: Northeast G&P $ 225 $ 222 $ 220
$ 219 $ 886 $ 227 $ 248 $ 246 $ 721 Atlantic-Gulf 405 368 434 454
1,661 453 462 431 1,346 West 400 424 433 394 1,651 389 372 426
1,187 NGL & Petchem Services 30 51 102 46 229 49 23 1 73 Other
— — — —
— (1 ) (1 )
(3 ) (5 )
Total Adjusted EBITDA
$ 1,060 $ 1,065
$ 1,189 $ 1,113
$ 4,427 $ 1,117
$ 1,104 $ 1,101
$ 3,322 Williams
Partners L.P. Consolidated Statement of Income (Loss)
(UNAUDITED)
2016 2017 (Dollars in millions, except
per-unit amounts) 1st Qtr 2nd Qtr 3rd Qtr
4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr
Year
Revenues:
Service revenues $ 1,226 $ 1,210 $ 1,252 $ 1,485 $ 5,173 $
1,256 $ 1,277 $ 1,304 $ 3,837 Product sales 428
530 655 705
2,318 727
642 581 1,950
Total revenues 1,654 1,740 1,907 2,190 7,491 1,983 1,919 1,885
5,787 Costs and expenses: Product costs 317 403 463 545 1,728 579
537 504 1,620 Operating and maintenance expenses 382 386 385 395
1,548 361 384 396 1,141 Depreciation and amortization expenses 435
432 426 427 1,720 433 423 424 1,280 Selling, general, and
administrative expenses 181 139 147 163 630 156 154 140 450 Gain on
sale of Geismar Interest — — — — — — — (1,095 ) (1,095 ) Impairment
of certain assets 6 396 1 54 457 1 2 1,142 1,145 Other (income)
expense - net 24 24
59 4 111
3 7 22
32 Total costs and expenses 1,345
1,780 1,481
1,588 6,194 1,533
1,507 1,533
4,573
Operating income (loss) 309
(40 ) 426
602 1,297
450 412
352 1,214
Equity earnings (losses) 97 101 104 95 397 107 125 115 347
Impairment of equity-method investments (112 ) — — (318 ) (430 ) —
— — — Other investing income (loss) - net — 1 28 — 29 271 2 4 277
Interest incurred (240 ) (239 ) (236 ) (234 ) (949 ) (221 ) (214 )
(210 ) (645 ) Interest capitalized 11 8 7 7 33 7 9 8 24 Other
income (expense) - net 15 12
16 19 62
49 15 14
78
Income (loss) before income
taxes 80 (157 ) 345 171
439 663 349 283 1,295 Provision
(benefit) for income taxes 1 (80 )
(6 ) 5 (80 )
3 1 (1 )
3
Net income (loss) 79 (77
) 351 166 519 660 348
284 1,292 Less: Net income attributable to
noncontrolling interests 29 13
25 21 88
26 28 25
79
Net income (loss) attributable to
controlling interests $ 50 $
(90 ) $ 326
$ 145 $ 431
$ 634 $ 320
$ 259 $ 1,213
Allocation of net income (loss) for calculation of earnings
per common unit: Net income (loss) attributable to controlling
interests $ 50 $ (90 ) $ 326 $ 145 $ 431 $ 634 $ 320 $ 259 $ 1,213
Allocation of net income (loss) to general partner (1) 202 207 72 —
517 — — — — Allocation of net income (loss) to Class B units (1)
(4 ) (8 ) 7
2 12 11 6
4 21
Allocation
of net income (loss) to common units (1) $
(148 ) $ (289 )
$ 247 $ 143
$ (98 ) $ 623
$ 314 $ 255
$ 1,192 Diluted earnings (loss) per
common unit: Net income (loss) per common unit (1) $ (0.25 ) $
(0.49 ) $ 0.42 $ 0.24 $ (0.17 ) $ 0.68 $ 0.33 $ 0.27 $ 1.26
Weighted average number of common units outstanding (thousands)
588,562 588,607 591,567 601,738 592,519 920,250 955,986 956,365
944,333
Cash distributions per common unit $
0.85 $ 0.85 $ 0.85 $
0.85 $ 3.40 $ 0.60 $
0.60 $ 0.60 $ 1.80 (1)
The sum for the quarters may not equal the total for the year due
to timing of unit issuances.
Williams Partners
L.P. Northeast G&P
(UNAUDITED)
2016 2017 (Dollars in millions) 1st Qtr
2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr
2nd Qtr 3rd Qtr Year
Revenues:
Service revenues:
Nonregulated gathering and processing fee-based revenue $ 186 $ 182
$ 179 $ 184 $ 731 $ 182 $ 183 $ 182 $ 547 Other fee revenues 37 40
39 42 158 40 38 36 114 Product sales: NGL sales from gas processing
4 3 3 4 14 4 4 2 10 Marketing sales 19
31 40 58
148 64 48
59 171 246 256 261 288 1,051 290
273 279 842 Intrasegment eliminations (4 ) (6
) (4 ) (5 ) (19 )
(5 ) (4 ) (4 ) (13 )
Total revenues 242 250 257 283 1,032 285 269 275 829 Segment
costs and expenses: NGL cost of goods sold 1 2 1 2 6 4 1 2 7
Marketing cost of goods sold 20 32 41 60 153 65 48 59 172 Other
segment costs and expenses (1) 99 91 95 98 383 91 93 102 286
Impairment of certain assets 4 4 — 5 13 1 1 121 123 Intrasegment
eliminations (4 ) (6 ) (4 )
(5 ) (19 ) (5 ) (4
) (4 ) (13 ) Total segment costs and
expenses 120 123 133 160 536 156 139 280 575 Proportional
Modified EBITDA of equity-method investments 98
95 90 74
357 97 117
120 334
Modified EBITDA 220 222 214 197
853 226 247 115 588 Adjustments
5 — 6
22 33 1
1 131 133
Adjusted EBITDA $ 225
$ 222 $ 220
$ 219 $ 886
$ 227 $ 248
$ 246 $ 721
Statistics for Operated Assets Gathering and
Processing Gathering volumes (Bcf per day) - Consolidated (2) 3.34
3.15 3.16 3.19 3.21 3.32 3.28 3.28 3.29 Gathering volumes (Bcf per
day) - Non-consolidated (3) 3.21 3.16 3.08 3.20 3.16 3.55 3.58 3.48
3.54 Plant inlet natural gas volumes (Bcf per day) (2) 0.31 0.31
0.34 0.37 0.33 0.39 0.40 0.45 0.41 Ethane equity sales
(Mbbls/d) 6 4 3 3 4 2 2 2 2 Non-ethane equity sales (Mbbls/d)
1 1 1
1 1 1
1 1 1
NGL equity sales (Mbbls/d) 7 5 4 4 5 3 3 3 3 Ethane
production (Mbbls/d) 14 18 22 20 18 17 22 17 19 Non-ethane
production (Mbbls/d) 11 12
16 15 14
15 17 19
17 NGL production (Mbbls/d) 25 30 38 35
32 32 39 36 36 (1) Includes operating expenses,
general and administrative expenses, and other income or expenses.
(2) Includes gathering volumes associated with Susquehanna Supply
Hub, Ohio Valley Midstream, and Utica Supply Hub, all of which are
consolidated. (3) Includes 100% of the volumes associated with
operated equity-method investments, including the Laurel Mountain
Midstream partnership; and the Bradford Supply Hub and a portion of
the Marcellus South Supply Hub within the Appalachia Midstream
Services partnership. Volumes handled by Blue Racer Midstream
(gathering and processing) and UEOM (processing only), which we do
not operate, are not included.
Williams Partners
L.P. Atlantic-Gulf
(UNAUDITED)
2016 2017 (Dollars in millions) 1st Qtr
2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr
2nd Qtr 3rd Qtr Year
Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue $ 92 $ 76
$ 131 $ 137 $ 436 $ 127 $ 136 $ 133 $ 396 Regulated transportation
revenue 349 331 339 348 1,367 354 358 381 1,093 Other fee revenues
24 41 41 42 148 54 42 38 134 Product sales: NGL sales from gas
processing 8 11 24 31 74 27 16 13 56 Marketing sales 45 75 78 84
282 90 75 66 231 Other sales — — 4 4 8 1 — 1 2 Tracked revenues
38 39 51
39 167 36
52 47 135
556 573 668 685 2,482 689 679 679 2,047 Intrasegment
eliminations (9 ) (10 ) (9 )
(6 ) (34 ) (19 )
(7 ) (9 ) (35 ) Total revenues 547 563
659 679 2,448 670 672 670 2,012 Segment costs and expenses:
NGL cost of goods sold 3 4 15 15 37 13 7 6 26 Marketing cost of
goods sold 45 74 78 83 280 88 75 65 228 Other cost of goods sold —
— 2 1 3 — — — — Impairment of certain assets 1 2 — — 3 — — — —
Other segment costs and expenses (1) 153 162 174 169 658 174 171
195 540 Tracked costs 38 39 51 39 167 36 52 47 135 Intrasegment
eliminations (9 ) (10 ) (9 )
(6 ) (34 ) (19 )
(7 ) (9 ) (35 ) Total segment costs and
expenses 231 271 311 301 1,114 292 298 304 894 Proportional
Modified EBITDA of equity-method investments 66
68 75 78
287 72 80
64 216
Modified
EBITDA 382 360 423 456 1,621
450 454 430 1,334 Adjustments 23
8 11
— 42 3 8
1 12
Adjusted
EBITDA $ 405 $ 368
$ 434 $ 456
$ 1,663 $ 453
$ 462 $ 431
$ 1,346
Statistics for
Operated Assets Gathering, Processing and Crude Oil
Transportation Gathering volumes (Bcf per day) - Consolidated (2)
0.30 0.30 0.52 0.53 0.41 0.32 0.29 0.31 0.31 Gathering volumes (Bcf
per day) - Non-consolidated (3) 0.53 0.54 0.60 0.60 0.56 0.55 0.54
0.39 0.49 Plant inlet natural gas volumes (Bcf per day) -
Consolidated (2) 0.64 0.60 0.84 0.78 0.72 0.56 0.57 0.52 0.55 Plant
inlet natural gas volumes (Bcf per day) - Non-consolidated (3) 0.56
0.54 0.60 0.60 0.57 0.54 0.53 0.39 0.49 Crude transportation
volumes (Mbbls/d) 98 99 126 128 113 131 135 137 134
Consolidated (2) Ethane margin ($/gallon) $ .03 $ .05 $ (.03 ) $
(.01 ) $ — $ .02 $ .03 $ .04 $ .03 Non-ethane margin ($/gallon) $
.30 $ .38 $ .26 $ .35 $ .31 $ .42 $ .36 $ .53 $ .42 NGL margin
($/gallon) $ .21 $ .18 $ .16 $ .20 $ .19 $ .26 $ .23 $ .26 $ .25
Ethane equity sales (Mbbls/d) 2 6 6 8 5 6 4 4 5 Non-ethane
equity sales (Mbbls/d) 4 4
11 12 8
9 6 3
6 NGL equity sales (Mbbls/d) 6 10 17 20
13 15 10 7 11 Ethane production (Mbbls/d) 13 17 16 19 16 14
14 13 14 Non-ethane production (Mbbls/d) 20
20 31 30
25 20 19
18 19 NGL production
(Mbbls/d) 33 37 47 49 41 34 33 31 33 Non-consolidated (3)
NGL equity sales (Mbbls/d) 5 5 5 5 5 5 4 5 5 NGL production
(Mbbls/d) 17 19 21 21 20 21 22 22 22 Transcontinental Gas
Pipe Line Throughput (Tbtu) 927.2 815.9 878.1 881.5 3,502.7 939.1
887.6 938.5 2,765.2 Avg. daily transportation volumes (Tbtu) 10.2
9.0 9.5 9.6 9.6 10.4 9.8 10.2 10.1 Avg. daily firm reserved
capacity (Tbtu) 12.0 11.5 11.6 11.9 11.7 12.8 13.2 14.1 13.4
(1) Includes operating expenses, general and administrative
expenses, and other income or expenses. (2) Excludes volumes
associated with equity-method investments that are not consolidated
in our results. (3) Includes 100% of the volumes associated with
operated equity-method investments.
Williams
Partners L.P. West
(UNAUDITED)
2016 2017 (Dollars in millions) 1st Qtr
2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr
2nd Qtr 3rd Qtr Year
Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue $ 376 $
379 $ 374 $ 593 $ 1,722 $ 364 $ 382 $ 398 $ 1,144 Regulated
transportation revenue 118 111 114 117 460 117 112 113 342 Other
fee revenues 42 44 43 44 173 43 38 39 120 Product sales: NGL sales
from gas processing 38 54 53 58 203 64 61 68 193 Olefin sales — — —
— — 1 — — 1 Marketing sales 269 342 396 504 1,511 506 490 561 1,557
Other sales 6 4 5 4 19 6 8 12 26 Tracked revenues —
1 — —
1 — 1
— 1 849 935 985
1,320 4,089 1,101 1,092 1,191 3,384 Intrasegment eliminations
(76 ) (101 ) (95 )
(109 ) (381 ) (127 ) (130 )
(162 ) (419 ) Total revenues 773 834
890 1,211 3,708 974 962 1,029 2,965 Segment costs and
expenses: NGL cost of goods sold 18 22 26 25 91 27 31 31 89
Marketing cost of goods sold 271 345 396 494 1,506 505 498 550
1,553 Other cost of goods sold 5 3 5 3 16 5 4 12 21 Other segment
costs and expenses (1) 252 231 223 235 941 204 220 209 633
Impairment of certain assets 1 49 1 49 100 — 1 1,021 1,022 Tracked
costs — 1 — — 1 — — 1 1 Intrasegment eliminations (76 )
(101 ) (95 ) (109 )
(381 ) (127 ) (130 )
(162 ) (419 ) Total segment costs and expenses
471 550 556 697 2,274 614 624 1,662 2,900 Proportional
Modified EBITDA of equity-method investments 25
28 29 28
110 25 18
18 61
Modified
EBITDA 327 312 363 542 1,544
385 356 (615 ) 126 Adjustments
73 112 70
(148 ) 107 4
16 1,041
1,061
Adjusted EBITDA $ 400
$ 424 $ 433
$ 394 $ 1,651
$ 389 $ 372
$ 426 $ 1,187
Statistics for Operated Assets Gathering and
Processing Gathering volumes (Bcf per day) 4.60 4.68 4.72 4.50 4.62
4.23 4.40 4.62 4.42 Plant inlet natural gas volumes (Bcf per day)
2.51 2.51 2.48 2.32 2.45 1.99 2.00 2.11 2.03 Ethane equity
sales (Mbbls/d) 4 15 6 4 7 3 11 11 8 Non-ethane equity sales
(Mbbls/d) 20 22 23
21 21 20
20 20
20 NGL equity sales (Mbbls/d) 24 37 29 25 28 23 31 31
28 Ethane margin ($/gallon) $ .03 $ .00 $ .00 $ .00 $ .01 $
.04 $ .00 $ .02 $ .02 Non-ethane margin ($/gallon) $ .26 $ .39 $
.31 $ .41 $ .34 $ .49 $ .40 $ .45 $ .45 NGL margin ($/gallon) $ .22
$ .23 $ .24 $ .34 $ .26 $ .43 $ .26 $ .30 $ .32 Ethane
production (Mbbls/d) 12 25 10 9 14 8 18 19 15 Non-ethane production
(Mbbls/d) 64 66 65
62 64 55
57 62
58 NGL production (Mbbls/d) 76 91 75 71 78 63 75 81
73 Northwest Pipeline LLC Throughput (Tbtu) 205.6 168.0
161.9 191.6 727.1 219.0 165.4 156.4 540.8 Avg. daily transportation
volumes (Tbtu) 2.3 1.8 1.8 2.1 2.0 2.4 1.8 1.7 2.0 Avg. daily firm
reserved capacity (Tbtu) 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0
Overland Pass Pipeline Company LLC (equity investment) - 100% NGL
Transportation volumes (Mbbls) 16,814 18,410 18,535 18,078 71,837
18,338 20,558 21,015 59,911 (1) Includes operating
expenses, general and administrative expenses, and other income or
expenses.
Williams Partners L.P. NGL &
Petchem Services
(UNAUDITED)
2016 2017 (Dollars in millions) 1st Qtr
2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr
2nd Qtr 3rd Qtr Year
Revenues:
Service revenue:
Nonregulated gathering & processing fee-based revenue $ 1 $ 4 $
— $ — $ 5 $ — $ — $ — $ — Other fee-based revenues 7 19 14 3 43 3 4
— 7 Product sales: NGL sales from gas processing 17 3 16 — 36 — — —
— Olefin sales 136 151 202 160 649 160 145 6 311 Marketing sales 28
27 45 39 139 56 38 3 97 Other sales — —
2 —
2 — — —
— 189 204 279 202 874 219 187 9 415
Intrasegment eliminations (13 ) (8 )
(21 ) (5 ) (47 ) (17 )
(26 ) — (43 )
Total revenues 176 196 258 197 827 202 161 9 372 Segment
costs and expenses: NGL cost of goods sold 12 2 10 — 24 — — — —
Olefins cost of goods sold 65 77 84 86 312 89 93 4 186 Marketing
cost of goods sold 28 29 41 40 138 52 40 3 95 Other cost of goods
sold 1 — 2 — 3 — — — — Gain on sale of Geismar Interest — — — — — —
— (1,095 ) (1,095 ) Impairment of certain assets — 341 — 1 342 — —
— — Other segment costs and expenses (1) 57 45 72 26 200 27 24 13
64 Intrasegment eliminations (13 ) (8 )
(21 ) (5 ) (47 ) (17 )
(26 ) — (43 )
Total segment costs and expenses 150 486 188 148 972 151 131 (1,075
) (793 )
Modified
EBITDA 26 (290 ) 70 49
(145 ) 51 30 1,084 1,165
Adjustments 4 341
32 (3 ) 374 (2 )
(7 ) (1,083 ) (1,092 )
Adjusted EBITDA $ 30 $
51 $ 102 $
46 $ 229 $
49 $ 23 $
1 $ 73
Statistics for Operated Assets Ethane equity sales
(Mbbls/d) 10 1 8 — 7 — — — — Non-ethane equity sales (Mbbls/d)
10 1 6
— 6 —
— — —
NGL equity sales (Mbbls/d) 20 2 14 — 13 — — — —
Ethane production (Mbbls/d) 10 1 8 — — — — — — Non-ethane
production (Mbbls/d) 8 2
8 — —
— — —
— NGL production (Mbbls/d) 18 3 16 — — — — — —
Petrochemical Services Geismar ethylene sales volumes
(million lbs) 423 391 419 405 1,638 266 300 — 566 Geismar ethylene
margin ($/lb) (2) $ .13 $ .15 $ .21 $ .15 $ .16 $ .19 $ .13 $ — $
.16 Canadian propylene sales volumes (millions lbs) 33 8 46 — 87 —
— — — Canadian alky feedstock sales volumes (million gallons) 7 2 6
— 15 — — — — (1) Includes operating expenses, general
and administrative expenses, and other income or expenses. (2)
Ethylene margin and ethylene margin per pound are calculated using
financial results determined in accordance with GAAP, which include
realized ethylene sales prices and ethylene COGS. Realized sales
and COGS per unit metrics may vary from publicly quoted market
indices or spot prices due to various factors, including, but not
limited to, basis differentials, transportation costs, contract
provisions, and inventory accounting methods.
Williams Partners L.P. Capital Expenditures and
Investments
(UNAUDITED)
2016 2017 (Dollars in millions) 1st Qtr
2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr
2nd Qtr 3rd Qtr Year
Capital
expenditures:
Northeast G&P $ 67 $ 55 $ 46 $ 56 $ 224 $ 58 $ 81 $ 173 $ 312
Atlantic-Gulf 300 410 380 345 1,435 388 398 371 1,157 West 62 33 63
70 228 57 58 94 209 NGL & Petchem Services 34 18 4 1 57 6 1 (1
) 6 Other — 2 (2 )
— — — 2
1 3
Total
(1) $ 463 $ 518
$ 491 $ 472
$ 1,944 $ 509 $
540 $ 638 $
1,687 Purchases of investments:
Northeast G&P $ 24 $ 40 $ (16 ) $ 24 $ 72 $ 20 $ 26 $ 24 $ 70
Atlantic-Gulf — — — — — — 1 — 1 West 39
19 26 21 105
32 — —
32
Total $ 63
$ 59 $ 10
$ 45 $ 177 $ 52
$ 27 $ 24
$ 103 Summary:
Northeast G&P $ 91 $ 95 $ 30 $ 80 $ 296 $ 78 $ 107 $ 197 $ 382
Atlantic-Gulf 300 410 380 345 1,435 388 399 371 1,158 West 101 52
89 91 333 89 58 94 241 NGL & Petchem Services 34 18 4 1 57 6 1
(1 ) 6 Other — 2 (2 )
— — — 2
1 3
Total
$ 526 $ 577
$ 501 $ 517
$ 2,121 $ 561 $
567 $ 662 $
1,790 Capital expenditures incurred and
purchases of investments: Increases to property, plant, and
equipment $ 498 $ 485 $ 446 $ 442 $ 1,871 $ 569 $ 586 $ 660 $ 1,815
Purchases of investments 63 59
10 45 177 52
27 24
103
Total $ 561
$ 544 $ 456
$ 487 $ 2,048 $
621 $ 613 $
684 $ 1,918 (1)
Increases to property, plant, and equipment $ 498 $ 485 $ 446 $ 442
$ 1,871 $ 569 $ 586 $ 660 $ 1,815 Changes in related accounts
payable and accrued liabilities (35 ) 33
45 30 73
(60 ) (46 ) (22 ) (128 )
Capital expenditures
$ 463 $
518 $ 491 $
472 $ 1,944 $ 509
$ 540 $ 638
$ 1,687 Selected
Financial Information
(UNAUDITED)
2016 2017 (Dollars in millions) 1st Qtr 2nd
Qtr 3rd Qtr 4th Qtr 1st Qtr 2nd Qtr 3rd
Qtr
Cash and cash equivalents
$ 125 $ 101 $ 68 $ 145 $ 625 $ 1,908
$ 1,165 Capital structure: Debt: Commercial paper $
135 $ 196 $ 2 $ 93 $ — $ — $ — Current $ 976 $ 786 $ 785 $ 785 $ —
$ 1,951 $ 502 Noncurrent $ 18,504 $ 19,116 $ 18,918 $ 17,685 $
17,065 $ 16,614 $ 16,000
View source
version on businesswire.com: http://www.businesswire.com/news/home/20171101006543/en/
Williams Partners L.P.Media Contact:Keith Isbell,
918-573-7308orInvestor Contact:Brett Krieg, 918-573-4614
Williams Companies (NYSE:WMB)
Historical Stock Chart
From Apr 2024 to May 2024
Williams Companies (NYSE:WMB)
Historical Stock Chart
From May 2023 to May 2024