WPZ
$35.68
Williams Partners LP
$.49
1.39%
Earnings Details
3rd Quarter September 2017
Wednesday, November 01, 2017 4:15:06 PM
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Summary

Williams Partners LP (WPZ) Recent Earnings

Williams Partners LP (WPZ) reported 3rd Quarter September 2017 earnings of $0.27 per share on revenue of $1.9 billion. The consensus earnings estimate was $0.39 per share. Revenue fell 1.2% compared to the same quarter a year ago.

Williams Partners LP is an energy infrastructure company. It owns and operates midstream gathering and processing assets, and interstate natural gas pipelines.

Results
Reported Earnings
$0.27
Earnings Whisper
-
Consensus Estimate
$0.39
Reported Revenue
$1.89 Bil
Revenue Estimate
Growth
Earnings Growth
Revenue Growth
Power Rating
Grade
Earnings Release

Williams Partners Reports Third-Quarter 2017 Financial Results

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. (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
2017
2016
2017
2016
are reported on a diluted basis. All amounts are attributable to
Williams Partners L.P.
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
Modified
Adjust.
Adjusted
Modified
Adjust.
Adjusted
Modified
Adjust.
Adjusted
Modified
Adjust.
Adjusted
EBITDA
EBITDA
EBITDA
EBITDA
EBITDA
EBITDA
EBITDA
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 (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 (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
7
9
8
7
31
6
11
8
25
nonregulated operations
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
--
--
--
--
--
(58 )
(58 )
(59 )
(175 )
contract restructurings
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
1.02
1.02
1.08
0.92
1.01
1.33
1.22
1.17
1.24
divided by Total cash distributed
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

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SOURCE: Williams Partners L.P.

Williams Partners L.P.
Media Contact:
Keith Isbell, 918-573-7308
or
Investor Contact:
Brett Krieg, 918-573-4614