Expects to Maintain Current Cash Distribution Level Through 2017
Provides Financial Update and Announces Actions to Strengthen Credit
Profile and Fund Fee-based Growth Portfolio
-
Cash Flow from Operations is $741 Million for 2Q 2016; $1.665
Billion Year-to-Date, Up Approximately 12% over First Half 2015
-
Continued Strong Financial Performance; Significant Cost Reductions
Achieved in 2Q
-
Expects to Maintain Quarterly Cash Distribution of $0.85 per Unit
or $3.40 Annualized through 2017
-
Expects to Implement Distribution Reinvestment Program (DRIP)
-
Williams Intends to Reinvest Approximately $1.7 Billion into
Williams Partners through 2017
-
Planned Asset Sale on Track to Close During the Second Half of 2016
-
Strengthening Credit Profile; Maintaining Commitment to Investment
Grade Credit Ratings
Williams Partners L.P. (NYSE: WPZ) today reported second quarter 2016
financial results that included strong cash flow from operations and
affirmed the partnership intends to maintain its quarterly cash
distribution of $0.85 per unit, or $3.40 annualized, through 2017 with
planned distribution growth beyond. Additionally, the partnership
announced actions it is taking to strengthen its position as the premier
provider of large-scale natural gas infrastructure by maintaining a
healthy credit profile, increasing its financial flexibility and driving
long-term growth.
|
|
|
|
|
|
|
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.
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAAP Measures
|
|
|
|
|
|
|
|
|
|
|
Cash Flow from Operations
|
|
$
|
741
|
|
|
$
|
796
|
|
|
|
$
|
1,665
|
|
|
$
|
1,493
|
|
Net income (loss)
|
|
|
($90
|
)
|
|
$
|
300
|
|
|
|
|
($40
|
)
|
|
$
|
389
|
|
Net income (loss) per common unit
|
|
|
($0.49
|
)
|
|
$
|
0.14
|
|
|
|
|
($0.74
|
)
|
|
|
($0.16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP Measures (1)
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
1,065
|
|
|
$
|
1,008
|
|
|
|
$
|
2,125
|
|
|
$
|
1,925
|
|
DCF attributable to partnership operations
|
|
$
|
737
|
|
|
$
|
701
|
|
|
|
$
|
1,476
|
|
|
$
|
1,347
|
|
Cash distribution coverage ratio
|
|
|
1.02
|
|
|
|
0.97
|
|
|
|
|
1.02
|
|
|
|
0.93
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 2016 Financial Results
Due primarily to a $341 million non-cash pre-tax impairment charge
associated with held-for-sale Canadian operations, Williams Partners
reported second quarter 2016 unaudited net loss of $90 million, a $390
million unfavorable change from second quarter 2015 net income. The
decrease also reflects the absence of $126 million of Geismar insurance
proceeds from the prior year and a $48 million impairment charge in 2016
related to a gathering system. These changes were partially offset by
lower costs and expenses, as well as a foreign tax provision impact
associated with the Canadian impairment charge.
Year-to-date Williams Partners reported unaudited net loss of $40
million, an unfavorable change of $429 million for the same six-month
reporting period in 2015 due primarily to the items affecting the second
quarter. The year-to-date decrease also reflects the first quarter
impairment of certain equity-method investments and higher interest
expense, partially offset by improved olefins margins and increased
contributions from Discovery’s Keathley Canyon Connector.
Williams Partners reported second quarter 2016 Adjusted EBITDA of $1.065
billion, a $57 million increase over second quarter 2015. The increase
is due primarily to $55 million lower G&A and operating expenses,
despite additional assets being in service. Fee-based revenues, which
were steady versus second quarter 2015, were impacted by a $34 million
reduction at Gulfstar One resulting from a planned shutdown to connect
the Gunflint tieback, partially offset by higher revenues from Transco
expansion projects.
Year-to-date, Williams Partners reported Adjusted EBITDA of $2.125
billion, an increase of $200 million over the same six-month reporting
period in 2015. The increase is due primarily to $75 million of higher
olefins margins, $61 million of higher fee-based revenues, $61 million
of lower operating and G&A expenses and $52 million of higher
proportional EBITDA from joint ventures. Partially offsetting these
increases were certain unfavorable items including a $15 million change
in foreign currency exchange gains and losses.
Distributable Cash Flow and Distributions
For second quarter 2016, Williams Partners generated $737 million in
distributable cash flow (DCF) attributable to partnership operations,
compared with $701 million in DCF attributable to partnership operations
for the same period last year. The $36 million increase in DCF for the
quarter was driven by a $57 million increase in Adjusted EBITDA,
partially offset by $38 million higher interest expense. The cash
distribution coverage was 1.02x versus 0.97x in second quarter 2015.
Year-to-date, Williams Partners generated $1.476 billion in DCF, an
increase of $129 million in DCF over the same six-month reporting period
in 2015. The increase was due to a $200 million increase in Adjusted
EBITDA partially offset by $75 million higher interest expense. The cash
distribution coverage for the first six-month reporting period was 1.02x
versus 0.93x for the same six-month period in 2015.
Williams Partners recently announced a regular quarterly cash
distribution of $0.85 per unit for its common unitholders.
CEO Perspective
Alan Armstrong, chief executive officer of Williams Partners’ general
partner, made the following comments:
“We own the premier natural gas focused asset base, and our strong
performance in the second quarter once again demonstrates that our
strategy positions Williams like no other company to benefit from
growing natural gas demand. In fact, we currently have projects in
negotiation or execution to add 7.6 Bcf per day of capacity to markets
served by Transco through 2020, which amounts to 65 percent of Wood
Mackenzie’s 5-year projected demand growth for natural gas along
Transco’s corridor. In 2018, we expect to have twice as much
fully-contracted capacity on Transco as we did in 2010. Quarter after
quarter, the significant advantages of increased fee-based revenues are
evident as we bring demand-driven projects into service. Additionally,
as we execute on current projects, our assets continue to attract a
steady number of requests for new market area capacity.
“Early in 2016 we embarked on several actions, including cost reduction
initiatives, to address the realities of slower growth in key supply
areas. We executed quickly on these actions and are already realizing
the benefits of these efforts in the current quarter and expect
additional traction in subsequent quarters.
“As we move forward, our organization is fully aligned, energized and
focused on simplifying the way we operate and make decisions. We are
committed to executing on our projects, lowering our overall risk, and
driving stockholder value by delivering on our growth strategy and
strengthening our balance sheet.”
Business Segment Performance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners
|
|
Modified and Adjusted EBITDA
|
Amounts in millions
|
|
2Q 2016
|
|
2Q 2015
|
|
|
|
YTD 2016
|
|
YTD 2015
|
|
|
Modified EBITDA
|
|
Adjust.
|
|
Adjusted EBITDA
|
|
Modified EBITDA
|
|
Adjust.
|
|
Adjusted EBITDA
|
|
|
|
Modified EBITDA
|
|
Adjust.
|
|
Adjusted EBITDA
|
|
Modified EBITDA
|
|
Adjust.
|
|
Adjusted EBITDA
|
Atlantic-Gulf
|
|
$
|
357
|
|
|
$
|
8
|
|
$
|
365
|
|
$
|
389
|
|
$
|
-
|
|
|
$
|
389
|
|
|
|
|
$
|
733
|
|
|
$
|
31
|
|
$
|
764
|
|
$
|
724
|
|
$
|
-
|
|
|
$
|
724
|
|
Central
|
|
|
134
|
|
|
|
112
|
|
|
246
|
|
|
160
|
|
|
72
|
|
|
|
232
|
|
|
|
|
|
291
|
|
|
|
181
|
|
|
472
|
|
|
293
|
|
|
157
|
|
|
|
450
|
|
NGL & Petchem Services
|
|
|
(261
|
)
|
|
|
341
|
|
|
80
|
|
|
158
|
|
|
(125
|
)
|
|
|
33
|
|
|
|
|
|
(208
|
)
|
|
|
345
|
|
|
137
|
|
|
164
|
|
|
(124
|
)
|
|
|
40
|
|
Northeast G&P
|
|
|
216
|
|
|
|
-
|
|
|
216
|
|
|
183
|
|
|
22
|
|
|
|
205
|
|
|
|
|
|
430
|
|
|
|
5
|
|
|
435
|
|
|
368
|
|
|
33
|
|
|
|
401
|
|
West
|
|
|
158
|
|
|
|
-
|
|
|
158
|
|
|
150
|
|
|
-
|
|
|
|
150
|
|
|
|
|
|
313
|
|
|
|
4
|
|
|
317
|
|
|
311
|
|
|
1
|
|
|
|
312
|
|
Other
|
|
|
-
|
|
|
|
-
|
|
|
-
|
|
|
13
|
|
|
(14
|
)
|
|
|
(1
|
)
|
|
|
|
|
-
|
|
|
|
-
|
|
|
-
|
|
|
10
|
|
|
(12
|
)
|
|
|
(2
|
)
|
Total
|
|
$
|
604
|
|
|
$
|
461
|
|
$
|
1,065
|
|
$
|
1,053
|
|
|
($45
|
)
|
|
$
|
1,008
|
|
|
|
|
$
|
1,559
|
|
|
$
|
566
|
|
$
|
2,125
|
|
$
|
1,870
|
|
$
|
55
|
|
|
$
|
1,925
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Definitions of modified EBITDA and adjusted EBITDA and
schedules reconciling these measures to net income are included in
this news release.
|
|
Atlantic-Gulf
Atlantic-Gulf operating area includes the Transco interstate gas
pipeline and a 41-percent interest in the Constitution interstate gas
pipeline development project, which Williams Partners consolidates. The
segment also includes the partnership’s significant natural gas
gathering and processing and crude oil production and handling and
transportation in the Gulf Coast region. These operations include a
51-percent consolidated interest in Gulfstar One, a 50-percent equity
method interest in Gulfstream and a 60-percent equity-method interest in
the Discovery pipeline and processing system.
Atlantic-Gulf reported Modified EBITDA of $357 million for second
quarter 2016, compared with $389 million for second quarter 2015. The
$32 million decrease is due primarily to $34 million lower fee-based
revenues at Gulfstar One caused by a planned month-long shutdown to
connect the Gunflint tieback, and other activity by producers on their
wells partially offset by $17 million higher fee-based revenues in other
areas – primarily from Transco’s new expansion projects. Results also
reflect an increase in operating costs.
Year-to-date, Atlantic-Gulf reported Modified EBITDA of $733 million, an
increase of $9 million over the same six-month reporting period in 2015.
The increase was primarily due to $28 million higher proportional EBITDA
from Discovery due to increased contributions from Keathley Canyon
Connector and $55 million higher fee-based revenues on Transco primarily
associated with expansion projects. These increases were partially
offset by $41 million of lower fee-based revenues from Gulfstar One,
primarily from the second quarter 2016 month-long shutdown to connect
the Gunflint tieback and other activity by producers on their wells.
Results were also unfavorably impacted by potential rate refunds
associated with litigation, severance-related costs, and Constitution
project development costs, all of which are excluded from Adjusted
EBITDA.
Central
Central operating area includes operations that were previously part of
the former Access Midstream segment located in Louisiana, Texas,
Arkansas and Oklahoma. These operations became the Central operating
area effective Jan. 1, 2016 and prior period segment disclosures have
been recast to reflect this change. Central provides gathering, treating
and compression services to producers under long-term, fee-based
contracts. The segment also includes a non-operated 50 percent interest
in the Delaware Basin gas gathering system in the Mid-Continent region.
The Central operating area reported Modified EBITDA of $134 million for
second quarter 2016, a decrease of $26 million from second quarter 2015.
The decrease is due primarily to a $48 million impairment charge related
to a gathering system. The impairment was partially offset by lower
operating and G&A expenses. The non-cash impairment charge is excluded
from Adjusted EBITDA.
Year-to-date, the Central operating area reported Modified EBITDA of
$291 million, a decrease of $2 million from the same six-month reporting
period in 2015. The decrease was primarily due to the previously
mentioned impairment charge, partially offset by lower operating and G&A
expenses due to cost reduction efforts and the absence of certain merger
and transition costs in the prior year. Adjusted EBITDA improved by $22
million, excluding the impairment charge and benefits from the absence
of prior year merger and transition costs.
NGL & Petchem Services
NGL & Petchem Services operating area includes an 88.5 percent interest
in an olefins production facility in Geismar, La., along with a refinery
grade propylene splitter and pipelines in the Gulf Coast region. This
segment also includes midstream operations in Alberta, Canada, along
with an oil sands offgas processing plant near Fort McMurray, 261 miles
of NGL and olefins pipelines and an NGL/olefins fractionation facility
at Redwater. This segment also includes the partnership’s energy
commodities marketing business, an NGL fractionator and storage
facilities near Conway, Kan. and a 50-percent equity-method interest in
Overland Pass Pipeline.
NGL & Petchem Services operating area reported Modified EBITDA of ($261)
million for second quarter 2016, compared with Modified EBITDA of $158
million for second quarter 2015. The $419 million decrease was due
primarily to the previously discussed impairment charge associated with
Canadian operations and absence in second quarter 2016 of the $126
million business interruption proceeds, partially offset by higher
fee-based revenues and olefins margins. Geismar olefins margins for
second quarter 2016 were favorable by $12 million, reflecting strong
operational production levels negatively impacted by lower ethylene
prices. Adjusted EBITDA, which excludes the impact of the impairment
charge and insurance proceeds, increased by $47 million reflecting the
higher fee-based revenues and olefins margins.
Year-to-date, NGL & Petchem Services operating area reported Modified
EBITDA of ($208) million compared with $164 million during the same
six-month reporting period in 2015. The decrease was due primarily to
the previously discussed impairment charge and absence in second quarter
2016 of the $126 million business interruption proceeds and $15 million
of unfavorable foreign exchange activity related to the partnership’s
Canadian business. Partially offsetting these unfavorable items were $72
million favorable olefins margins at Geismar and $30 million favorable
fee-based revenues due primarily to new fees associated with Williams’
Canadian offgas processing plant that came online in first quarter 2016
at CNRL’s upgrader. Adjusted EBITDA, which excludes the impairment
charge and insurance proceeds, increased by $97 million.
Northeast G&P
Northeast G&P operating area now includes the Marcellus South, Bradford
and Utica midstream gathering and processing operations that were within
the former Access Midstream segment. These operations became part of
Northeast G&P effective Jan. 1, 2016 and prior period segment
disclosures have been recast to reflect this change. Northeast G&P also
includes the Susquehanna Supply Hub and Ohio Valley Midstream, as well
as its 69-percent equity investment in Laurel Mountain Midstream, and
its 58.4-percent equity investment in Caiman Energy II. Caiman Energy II
owns a 50 percent interest in Blue Racer Midstream.
Northeast G&P operating area reported Modified EBITDA of $216 million
for second quarter 2016, compared with $183 million for second quarter
2015. The quarter to quarter increase was due primarily to $25 million
lower operating and G&A expenses and the absence of $20 million in
certain asset impairment charges recorded in second quarter 2015.
Adjusted EBITDA increased by $11 million and excludes the prior year
impairments.
Year-to-date, Northeast G&P operating area reported Modified EBITDA of
$430 million, an increase of $62 million over the same six-month
reporting period in 2015. The increase is due primarily to lower
operating and G&A expenses, increased proportional Modified EBITDA of
equity-method investments, higher fee-based revenues, and the absence of
certain 2015 impairment charges. Adjusted EBITDA increased by $34
million and excludes the prior year impairment charges.
West
West operating area includes the partnership’s Northwest Pipeline
interstate gas pipeline system, as well as gathering, processing and
treating operations in Wyoming, the Piceance Basin and the Four Corners
area.
West operating area reported Modified EBITDA of $158 million for second
quarter 2016 compared with $150 million for second quarter 2015. The $8
million increase was due primarily to lower operating and G&A expenses.
Year-to-date, the West operating area reported Modified EBITDA of $313
million compared with $311 million over the same six-month reporting
period in 2015. The increase was due primarily to lower operating and
G&A expenses. Year-to-date, the West operating area reported Adjusted
EBITDA of $317 million compared with Adjusted EBITDA of $312 million
over the same six-month reporting period in 2015.
Williams Partners Expects to Implement Distribution Reinvestment
Program (DRIP) in Third Quarter 2016; Williams Intends to Reinvest
Approximately $1.7 Billion into Williams Partners through 2017
Williams Partners and Williams announced immediate measures designed to
enhance value, strengthen Williams Partners’ credit profile and fund the
development of a significant portfolio of fee-based growth projects at
Williams Partners, while maintaining flexibility to review financial and
operational plans.
Williams intends to reinvest approximately $1.7 billion into Williams
Partners through 2017.
Williams plans to reinvest $500 million into Williams Partners in 2016
including $250 million in the third quarter via a private purchase of
common units with the balance reinvested in the fourth quarter via the
DRIP. An additional $1.2 billion is planned to be reinvested in 2017 via
the DRIP.
The DRIP is expected to be activated in the third quarter of 2016 and
available for the quarterly cash distribution that will be paid to
limited partners in November of 2016. Williams Partners expects the DRIP
will enable limited partner unitholders to reinvest all or a portion of
the quarterly cash distributions they would receive from their ownership
of limited partner units to purchase common units.
Ongoing Initiatives Continue to Strengthen Williams Partners’ Credit
Profile
In addition to the implementation of the DRIP program, the partnership
confirmed that:
-
Williams and Williams Partners expect to finalize the agreement on the
sale of their Canadian business during the third quarter of 2016, with
expected combined proceeds in excess of $1 billion, with Williams
Partners’ share in excess of $800 million, further reducing external
capital-funding needs;
-
Williams Partners continues to make significant progress on its
ongoing cost reduction program, with $55 million in lower adjusted
costs for second quarter 2016 versus the prior year period despite
additional assets being in service; additional cost-savings
initiatives are expected in the balance of the year;
-
Williams Partners plans to access the public equity market via
Williams Partners’ ATM program or other means and may access the
public debt market as needed while maintaining investment grade credit
metrics.
Guidance
Current guidance for 2016 is set out in the following table:
|
|
|
|
|
|
|
|
|
|
|
Williams Partners
|
|
|
2016
|
|
|
|
Williams Partners
|
|
|
2016
|
|
|
2017
|
(Amount in billions)
|
|
|
|
|
|
(Amount in billions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
0.9
|
|
|
|
Growth Capital & Investment Expenditures
|
|
$
|
1.9
|
|
$
|
3.1
|
Adjusted EBITDA (1)
|
|
$
|
4.3
|
|
|
|
Growth Capital for Transco (2)
|
|
$
|
1.3
|
|
$
|
2.4
|
Distributable Cash Flow (1)
|
|
$
|
2.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Adjusted EBITDA and Distributable Cash Flow are non-GAAP
measures; reconcilations to the most relevant measures are
attached in this news release.
|
(2)
|
|
The numbers listed reflect 68% of total growth capex in 2016
and 77% of total growth capex in 2017.
|
|
|
|
Second-Quarter 2016 Materials to be Posted Shortly; Q&A Webcast
Scheduled for Tomorrow
Williams Partners’ second quarter 2016 financial results package will be
posted shortly at www.williams.com.
Williams and Williams Partners plan to jointly host a Q&A live webcast
on Tuesday, Aug. 2 at 9:30 a.m. EDT. A limited number of phone lines
will be available at 800-723-6604. International callers should dial
785-830-7977. The conference ID is 4335926. A link to the webcast, as
well as replays of the webcast in both streaming and downloadable
podcast formats, will be available for two weeks following the event at www.williams.com.
Form 10-Q
The company plans to file its second quarter 2016 Form 10-Q with the
Securities and Exchange Commission this week. Once filed, the document
will be available on both SEC and Williams 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
Securities and Exchange Commission.
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 and may
include assumed business interruption insurance related to the Geismar
plant. 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 calculated 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 (NYSE: WPZ) 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 and also in
Canada. Williams Partners has operations across the natural gas value
chain from gathering, processing and interstate transportation of
natural gas and natural gas liquids to petchem production of ethylene,
propylene and other olefins. 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
North American natural gas infrastructure, owns 60 percent of Williams
Partners, including all of the 2 percent general-partner interest. www.williams.com
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
in this report 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:
Expected levels of cash distributions with respect to general partner
interests, incentive distribution rights and limited partner interests;
Our and our affiliates’ future credit ratings;
Amounts and nature of future capital expenditures;
Expansion of our business and operations;
Financial condition and liquidity;
Business strategy;
Cash flow from operations or results of operations;
Seasonality of certain business components;
Natural gas, natural gas liquids, and olefins 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 in this report. 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 have sufficient cash from operations to enable us to pay
current and expected levels of cash distributions, if any, following the
establishment of cash reserves and payment of fees and expenses,
including payments to our general partner;
Whether we will be able to effectively execute our financing plan
including the establishment of a distribution reinvestment plan (DRIP)
and the receipt of anticipated levels of proceeds from planned asset
sales;
Availability of supplies, including lower than anticipated volumes
from third parties served by our midstream business, and market demand;
Volatility of pricing including the effect of lower than anticipated
energy commodity prices and margins;
Inflation, interest rates, fluctuation in foreign exchange 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 of alternative energy sources;
Availability of adequate insurance coverage and the impact of
operational and developmental hazards and unforeseen interruptions;
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;
Williams’ costs and funding obligations for defined benefit pension
plans and other postretirement benefit plans;
Our allocated 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 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 and referred to below may cause our intentions to change
from those statements of intention set forth in this report. 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 below in addition to the other information in this
report. If any of the following 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 26, 2016 and
in Part II, Item 1A. Risk Factors in our Quarterly Reports on Form 10-Q
available from our office or from our website at www.williams.com.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Non-GAAP Measures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(UNAUDITED)
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015
|
|
|
2016
|
|
(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)
|
|
$
|
112
|
|
|
$
|
332
|
|
|
$
|
(167
|
)
|
|
$
|
(1,635
|
)
|
|
$
|
(1,358
|
)
|
|
$
|
79
|
|
|
$
|
(77
|
)
|
|
$
|
2
|
|
|
|
|
Provision (benefit) for income taxes
|
|
|
3
|
|
|
|
—
|
|
|
|
1
|
|
|
|
(3
|
)
|
|
|
1
|
|
|
|
1
|
|
|
|
(80
|
)
|
|
|
(79
|
)
|
|
|
|
Interest expense
|
|
|
192
|
|
|
|
203
|
|
|
|
205
|
|
|
|
211
|
|
|
|
811
|
|
|
|
229
|
|
|
|
231
|
|
|
|
460
|
|
|
|
|
Equity (earnings) losses
|
|
|
(51
|
)
|
|
|
(93
|
)
|
|
|
(92
|
)
|
|
|
(99
|
)
|
|
|
(335
|
)
|
|
|
(97
|
)
|
|
|
(101
|
)
|
|
|
(198
|
)
|
|
|
|
Impairment of equity-method investments
|
|
|
—
|
|
|
|
—
|
|
|
|
461
|
|
|
|
898
|
|
|
|
1,359
|
|
|
|
112
|
|
|
|
—
|
|
|
|
112
|
|
|
|
|
Other investing (income) loss
|
|
|
(1
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
—
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
Proportional Modified EBITDA of equity-method investments
|
|
|
136
|
|
|
|
183
|
|
|
|
185
|
|
|
|
195
|
|
|
|
699
|
|
|
|
189
|
|
|
|
191
|
|
|
|
380
|
|
|
|
|
Impairment of goodwill
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,098
|
|
|
|
1,098
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
Depreciation and amortization expenses
|
|
|
419
|
|
|
|
419
|
|
|
|
423
|
|
|
|
441
|
|
|
|
1,702
|
|
|
|
435
|
|
|
|
432
|
|
|
|
867
|
|
|
|
|
Accretion for asset retirement obligations associated with
nonregulated operations
|
|
|
7
|
|
|
|
9
|
|
|
|
5
|
|
|
|
7
|
|
|
|
28
|
|
|
|
7
|
|
|
|
9
|
|
|
|
16
|
|
|
|
|
Modified EBITDA
|
|
|
817
|
|
|
|
1,053
|
|
|
|
1,021
|
|
|
|
1,112
|
|
|
|
4,003
|
|
|
|
955
|
|
|
|
604
|
|
|
|
1,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated minimum volume commitments
|
|
|
55
|
|
|
|
55
|
|
|
|
65
|
|
|
|
(175
|
)
|
|
|
—
|
|
|
|
60
|
|
|
|
64
|
|
|
|
124
|
|
|
|
|
Severance and related costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
25
|
|
|
|
—
|
|
|
|
25
|
|
|
|
|
Potential rate refunds associated with rate case litigation
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
15
|
|
|
|
—
|
|
|
|
15
|
|
|
|
|
Merger and transition related expenses
|
|
|
32
|
|
|
|
14
|
|
|
|
2
|
|
|
|
2
|
|
|
|
50
|
|
|
|
5
|
|
|
|
—
|
|
|
|
5
|
|
|
|
|
Constitution Pipeline project development costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
8
|
|
|
|
8
|
|
|
|
|
Share of impairment at equity-method investment
|
|
|
8
|
|
|
|
1
|
|
|
|
17
|
|
|
|
7
|
|
|
|
33
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
Geismar Incident adjustment for insurance and timing
|
|
|
—
|
|
|
|
(126
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(126
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
Loss related to Geismar Incident
|
|
|
1
|
|
|
|
1
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
Impairment of certain assets
|
|
|
3
|
|
|
|
24
|
|
|
|
2
|
|
|
|
116
|
|
|
|
145
|
|
|
|
—
|
|
|
|
389
|
|
|
|
389
|
|
|
|
|
Loss (recovery) related to Opal incident
|
|
|
1
|
|
|
|
—
|
|
|
|
(8
|
)
|
|
|
1
|
|
|
|
(6
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
Gain on extinguishment of debt
|
|
|
—
|
|
|
|
(14
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(14
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
Expenses associated with strategic alternatives
|
|
|
—
|
|
|
|
—
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
Total EBITDA adjustments
|
|
|
100
|
|
|
|
(45
|
)
|
|
|
79
|
|
|
|
(48
|
)
|
|
|
86
|
|
|
|
105
|
|
|
|
461
|
|
|
|
566
|
|
|
|
|
Adjusted EBITDA
|
|
|
917
|
|
|
|
1,008
|
|
|
|
1,100
|
|
|
|
1,064
|
|
|
|
4,089
|
|
|
|
1,060
|
|
|
|
1,065
|
|
|
|
2,125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures (1)
|
|
|
(54
|
)
|
|
|
(80
|
)
|
|
|
(114
|
)
|
|
|
(114
|
)
|
|
|
(362
|
)
|
|
|
(58
|
)
|
|
|
(75
|
)
|
|
|
(133
|
)
|
|
|
|
Interest expense (cash portion) (2)
|
|
|
(204
|
)
|
|
|
(207
|
)
|
|
|
(219
|
)
|
|
|
(214
|
)
|
|
|
(844
|
)
|
|
|
(241
|
)
|
|
|
(245
|
)
|
|
|
(486
|
)
|
|
|
|
Cash taxes
|
|
|
(1
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(1
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
Income attributable to noncontrolling interests (3)
|
|
|
(23
|
)
|
|
|
(32
|
)
|
|
|
(27
|
)
|
|
|
(29
|
)
|
|
|
(111
|
)
|
|
|
(29
|
)
|
|
|
(13
|
)
|
|
|
(42
|
)
|
|
|
|
WPZ restricted stock unit non-cash compensation
|
|
|
7
|
|
|
|
6
|
|
|
|
7
|
|
|
|
7
|
|
|
|
27
|
|
|
|
7
|
|
|
|
5
|
|
|
|
12
|
|
|
|
|
Plymouth incident adjustment
|
|
|
4
|
|
|
|
6
|
|
|
|
7
|
|
|
|
4
|
|
|
|
21
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow attributable to Partnership Operations
|
|
|
646
|
|
|
|
701
|
|
|
|
754
|
|
|
|
718
|
|
|
|
2,819
|
|
|
|
739
|
|
|
|
737
|
|
|
|
1,476
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash distributed (4)
|
|
$
|
725
|
|
|
$
|
723
|
|
|
$
|
723
|
|
|
$
|
725
|
|
|
$
|
2,896
|
|
|
$
|
725
|
|
|
$
|
725
|
|
|
$
|
1,450
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coverage ratios:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow attributable to partnership operations
divided by Total cash distributed
|
|
|
0.89
|
|
|
|
0.97
|
|
|
|
1.04
|
|
|
|
0.99
|
|
|
|
0.97
|
|
|
|
1.02
|
|
|
|
1.02
|
|
|
|
1.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) divided by Total cash distributed
|
|
|
0.15
|
|
|
|
0.46
|
|
|
|
(0.23
|
)
|
|
|
(2.26
|
)
|
|
|
(0.47
|
)
|
|
|
0.11
|
|
|
|
(0.11
|
)
|
|
|
0.00
|
|
Notes:
|
(1)
|
|
Includes proportionate share of maintenance capital expenditures of
equity investments.
|
|
|
|
|
|
(2)
|
|
Includes proportionate share of interest expense of equity
investments.
|
|
|
|
|
|
(3)
|
|
Income attributable to noncontrolling interests for the fourth
quarter 2015 excludes allocable share of impairment of goodwill.
|
|
|
|
|
|
(4)
|
|
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 for the 2015 third
quarter, fourth quarter, and year by $209 million, $209 million, and
$418 million, respectively, and by $10 million in the first quarter
of 2016.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.
|
Reconciliation of Non-GAAP “Modified EBITDA” to Non-GAAP
“Adjusted EBITDA”
|
(UNAUDITED)
|
|
|
|
|
|
2015
|
|
|
2016
|
|
(Dollars in millions)
|
|
1st Qtr
|
|
2nd Qtr
|
|
3rd Qtr
|
|
4th Qtr
|
|
Year
|
|
1st Qtr
|
|
2nd Qtr
|
|
Year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Modified EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
|
|
$
|
133
|
|
|
$
|
160
|
|
|
$
|
163
|
|
|
$
|
384
|
|
|
$
|
840
|
|
|
$
|
157
|
|
$
|
134
|
|
|
$
|
291
|
|
|
Northeast G&P
|
|
|
185
|
|
|
|
183
|
|
|
|
189
|
|
|
|
196
|
|
|
|
753
|
|
|
|
214
|
|
|
216
|
|
|
|
430
|
|
|
Atlantic-Gulf
|
|
|
335
|
|
|
|
389
|
|
|
|
414
|
|
|
|
385
|
|
|
|
1,523
|
|
|
|
376
|
|
|
357
|
|
|
|
733
|
|
|
West
|
|
|
161
|
|
|
|
150
|
|
|
|
169
|
|
|
|
77
|
|
|
|
557
|
|
|
|
155
|
|
|
158
|
|
|
|
313
|
|
|
NGL & Petchem Services
|
|
|
6
|
|
|
|
158
|
|
|
|
85
|
|
|
|
72
|
|
|
|
321
|
|
|
|
53
|
|
|
(261
|
)
|
|
|
(208
|
)
|
|
Other
|
|
|
(3
|
)
|
|
|
13
|
|
|
|
1
|
|
|
|
(2
|
)
|
|
|
9
|
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Total Modified EBITDA
|
|
$
|
817
|
|
|
$
|
1,053
|
|
|
$
|
1,021
|
|
|
$
|
1,112
|
|
|
$
|
4,003
|
|
|
$
|
955
|
|
$
|
604
|
|
|
$
|
1,559
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated minimum volume commitments
|
|
$
|
55
|
|
|
$
|
55
|
|
|
$
|
65
|
|
|
$
|
(175
|
)
|
|
$
|
—
|
|
|
$
|
60
|
|
$
|
64
|
|
|
$
|
124
|
|
|
|
Severance and related costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
6
|
|
|
—
|
|
|
|
6
|
|
|
|
ACMP Merger and transition costs
|
|
|
30
|
|
|
|
14
|
|
|
|
2
|
|
|
|
2
|
|
|
|
48
|
|
|
|
3
|
|
|
—
|
|
|
|
3
|
|
|
|
Impairment of certain assets
|
|
|
—
|
|
|
|
3
|
|
|
|
—
|
|
|
|
8
|
|
|
|
11
|
|
|
|
—
|
|
|
48
|
|
|
|
48
|
|
|
|
Total Central adjustments
|
|
|
85
|
|
|
|
72
|
|
|
|
67
|
|
|
|
(165
|
)
|
|
|
59
|
|
|
|
69
|
|
|
112
|
|
|
|
181
|
|
|
|
Northeast G&P
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and related costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
3
|
|
|
—
|
|
|
|
3
|
|
|
|
Share of impairment at equity-method investments
|
|
|
8
|
|
|
|
1
|
|
|
|
17
|
|
|
|
7
|
|
|
|
33
|
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
ACMP Merger and transition costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2
|
|
|
—
|
|
|
|
2
|
|
|
|
Impairment of certain assets
|
|
|
3
|
|
|
|
21
|
|
|
|
2
|
|
|
|
6
|
|
|
|
32
|
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Total Northeast G&P adjustments
|
|
|
11
|
|
|
|
22
|
|
|
|
19
|
|
|
|
13
|
|
|
|
65
|
|
|
|
5
|
|
|
—
|
|
|
|
5
|
|
|
|
Atlantic-Gulf
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Potential rate refunds associated with rate case litigation
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
15
|
|
|
—
|
|
|
|
15
|
|
|
|
Severance and related costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
8
|
|
|
—
|
|
|
|
8
|
|
|
|
Constitution Pipeline project development costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
8
|
|
|
|
8
|
|
|
|
Impairment of certain assets
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
5
|
|
|
|
5
|
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Total Atlantic-Gulf adjustments
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
5
|
|
|
|
5
|
|
|
|
23
|
|
|
8
|
|
|
|
31
|
|
|
|
West
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and related costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
4
|
|
|
—
|
|
|
|
4
|
|
|
|
Impairment of certain assets
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
97
|
|
|
|
97
|
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Loss (recovery) related to Opal incident
|
|
|
1
|
|
|
|
—
|
|
|
|
(8
|
)
|
|
|
1
|
|
|
|
(6
|
)
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Total West adjustments
|
|
|
1
|
|
|
|
—
|
|
|
|
(8
|
)
|
|
|
98
|
|
|
|
91
|
|
|
|
4
|
|
|
—
|
|
|
|
4
|
|
|
|
NGL & Petchem Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Severance and related costs
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
4
|
|
|
—
|
|
|
|
4
|
|
|
|
Loss related to Geismar Incident
|
|
|
1
|
|
|
|
1
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Impairment of certain assets
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
341
|
|
|
|
341
|
|
|
|
Geismar Incident adjustment for insurance and timing
|
|
|
—
|
|
|
|
(126
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(126
|
)
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Total NGL & Petchem Services adjustments
|
|
|
1
|
|
|
|
(125
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(124
|
)
|
|
|
4
|
|
|
341
|
|
|
|
345
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ACMP Merger-related expenses
|
|
|
2
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Expenses associated with strategic alternatives
|
|
|
—
|
|
|
|
—
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Gain on extinguishment of debt
|
|
|
—
|
|
|
|
(14
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
(14
|
)
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Total Other adjustments
|
|
|
2
|
|
|
|
(14
|
)
|
|
|
1
|
|
|
|
1
|
|
|
|
(10
|
)
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Adjustments
|
|
$
|
100
|
|
|
$
|
(45
|
)
|
|
$
|
79
|
|
|
$
|
(48
|
)
|
|
$
|
86
|
|
|
$
|
105
|
|
$
|
461
|
|
|
$
|
566
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Central
|
|
$
|
218
|
|
|
$
|
232
|
|
|
$
|
230
|
|
|
$
|
219
|
|
|
$
|
899
|
|
|
$
|
226
|
|
$
|
246
|
|
|
$
|
472
|
|
|
Northeast G&P
|
|
|
196
|
|
|
|
205
|
|
|
|
208
|
|
|
|
209
|
|
|
|
818
|
|
|
|
219
|
|
|
216
|
|
|
|
435
|
|
|
Atlantic-Gulf
|
|
|
335
|
|
|
|
389
|
|
|
|
414
|
|
|
|
390
|
|
|
|
1,528
|
|
|
|
399
|
|
|
365
|
|
|
|
764
|
|
|
West
|
|
|
162
|
|
|
|
150
|
|
|
|
161
|
|
|
|
175
|
|
|
|
648
|
|
|
|
159
|
|
|
158
|
|
|
|
317
|
|
|
NGL & Petchem Services
|
|
|
7
|
|
|
|
33
|
|
|
|
85
|
|
|
|
72
|
|
|
|
197
|
|
|
|
57
|
|
|
80
|
|
|
|
137
|
|
|
Other
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
2
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
—
|
|
|
—
|
|
|
|
—
|
|
|
|
Total Adjusted EBITDA
|
|
$
|
917
|
|
|
$
|
1,008
|
|
|
$
|
1,100
|
|
|
$
|
1,064
|
|
|
$
|
4,089
|
|
|
$
|
1,060
|
|
$
|
1,065
|
|
|
$
|
2,125
|
|
|
|
|
|
|
Williams Partners L.P.
|
|
|
|
|
Reconciliation of Non-GAAP Measures
|
|
|
|
|
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
(Dollars in billions)
|
|
|
|
Guidance
|
|
|
|
|
|
|
|
|
|
Williams Partners L.P.
|
|
|
|
|
|
Reconciliation of GAAP "Net Income (Loss)" to Non-GAAP "Modified
EBITDA", "Adjusted EBITDA", and "Distributable cash flow”
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
|
$
|
0.9
|
|
|
|
|
Provision (benefit) for income taxes
|
|
|
|
|
(0.1
|
)
|
|
|
|
Interest expense
|
|
|
|
|
0.9
|
|
|
|
|
Equity (earnings) losses
|
|
|
|
|
(0.4
|
)
|
|
|
|
Impairment of equity-method investments
|
|
|
|
|
0.1
|
|
|
|
|
Proportional Modified EBITDA of equity-method investments
|
|
|
|
|
0.7
|
|
|
|
|
Depreciation and amortization expenses and accretion for asset
retirement obligations
|
|
|
|
1.8
|
|
|
|
|
Modified EBITDA
|
|
|
|
|
3.9
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments:
|
|
|
|
|
|
|
|
Severance and related costs
|
|
$
|
0.025
|
|
|
|
|
|
Potential rate refunds associated with rate case litigation
|
|
|
0.015
|
|
|
|
|
|
Merger and transition related expenses
|
|
|
0.005
|
|
|
|
|
|
Constitution Pipeline project development costs
|
|
|
0.008
|
|
|
|
|
|
Impairment of certain assets
|
|
|
0.389
|
|
|
|
|
|
Total EBITDA adjustments
|
|
|
|
|
0.4
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
|
|
|
4.3
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance capital expenditures (1)
|
|
|
|
|
(0.4
|
)
|
|
|
|
Interest expense (cash portion) (2)
|
|
|
|
|
(1.0
|
)
|
|
|
|
Income attributable to noncontrolling interests, cash taxes and other
|
|
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow attributable to Partnership Operations
|
|
|
|
$
|
2.8
|
|
|
|
|
|
|
|
|
|
Notes:
|
(1) Includes proportionate share of maintenance capital
expenditures of equity-method investments.
|
(2) Includes proportionate share of interest expense of
equity-method investments.
|
View source version on businesswire.com: http://www.businesswire.com/news/home/20160801006182/en/
Copyright Business Wire 2016