WILLIAMS PARTNERS L.P. - FORM 8-K - EX-99.1

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EXHIBIT 99.1



News Release	Williams Partners L.P. (NYSE: WPZ) One Williams Center Tulsa, OK 74172 800-600-3782
News Release

DATE: Nov. 1, 2017



MEDIA CONTACT:	INVESTOR CONTACT:
Keith Isbell (918) 573-7308	Brett Krieg (918) 573-4614

Williams Partners Reports Third-Quarter 2017 Financial Results


•	3Q 2017 Net Income of $259 Million


•	3Q 2017 Adjusted EBITDA of $1.101 Billion


•	3Q 2017 Cash Distribution Coverage Ratio of 1.17x; 1.24x Year-to-Date


•	Placed 4 Transco Expansions (Gulf Trace, Hillabee Phase 1, Dalton Expansion, and New York Bay Expansion) Into Service to Date in 2017; Design Capacity Up 25%


•	Williams Partners Continues to Significantly Improve Credit Profile; Net Debt (Long-term Debt Less Cash) Reduced by $3 Billion Since Jan. 1, 2017


•	Achieved Key Milestones for Atlantic Sunrise Project

TULSA, Okla. – Williams Partners L.P. (NYSE: WPZ) today announced its financial results for the three and nine months ended Sept. 30, 2017.



Summary Financial Information	3Q						YTD
Amounts in millions, except per-unit amounts. Per unit amounts are reported on a diluted basis. All amounts are attributable to Williams Partners L.P.	2017			2016			2017			2016

GAAP Measures
Cash Flow from Operations		$596			$685			$2,103			$2,351
Net income (loss)		$259			$326			$1,213			$286
Net income (loss) per common unit		$0.27			$0.42			$1.26			($0.32	)

Non-GAAP Measures (1)
Adjusted EBITDA		$1,101			$1,189			$3,322			$3,314
DCF attributable to partnership operations		$669			$795			$2,119			$2,271
Cash distribution coverage ratio	1.17		x	1.08		x	1.24		x	1.04		x

(1) Adjusted EBITDA, distributable cash flow (DCF) and cash coverage ratio are non-GAAP measures. Reconciliations to the most relevant measures included in GAAP are attached to this news release.

Third-Quarter 2017 Financial Results

Williams Partners reported unaudited third-quarter 2017 net income attributable to controlling interests of $259 million, a $67 million decrease from third-quarter 2016. The unfavorable change was driven primarily by the absence of results associated with the Geismar olefins facility, which was sold July 6, 2017, and the partnership's former Canadian business, which was sold in September 2016. In addition, results were negatively impacted by impairments of certain assets, largely offset by the gain related to the sale of the Geismar facility.

Year-to-date, Williams Partners reported unaudited net income attributable to controlling interests of $1.213 billion, a $927 million improvement over the same nine-month reporting period in 2016. The favorable change was driven primarily by increased fee-based revenues from expansion projects, and gains on the sale of assets and equity investments. These favorable results were partially offset by higher impairment losses on assets between the periods and the decrease related to the previously mentioned sales of the Geismar olefins facility and the partnership's former Canadian operations.

Williams Partners reported third-quarter 2017 Adjusted EBITDA of $1.101 billion, an $88 million decrease from third-quarter 2016. The unfavorable change was driven primarily by the absence of $101 million of Adjusted EBITDA contribution from the NGL & Petchem Services segment associated with the previously described assets sold. Williams Partners' current businesses increased Adjusted EBITDA by approximately $13 million including an unfavorable impact of approximately $8 million from Hurricanes Harvey and Irma.

Year-to-date, Williams Partners reported Adjusted EBITDA of $3.322 billion, an $8 million increase over the corresponding nine-month reporting period in 2016. The comparison includes an approximately $110 million decrease from the NGL & Petchem Services segment associated with the previously described assets that were sold. Williams Partners' current businesses increased Adjusted EBITDA by approximately $118 million during the period. Favorable results included increased fee-based revenues, improved commodity margins, lower selling, general and administrative (SG&A) expenses and increased proportional EBITDA from joint ventures. Partially offsetting the increases were higher operating and maintenance (O&M) expenses.

Distributable Cash Flow and Distributions

For third-quarter 2017, Williams Partners generated $669 million in distributable cash flow (DCF) attributable to partnership operations, compared with $795 million in DCF attributable to partnership operations for third-quarter 2016. DCF was unfavorably impacted by the change in Adjusted EBITDA described above. DCF for third-quarter 2017 was also reduced by $59 million for the removal of non-cash deferred revenue amortization associated with the fourth-quarter 2016 contract restructurings in the Barnett Shale and Mid-Continent region. Partially offsetting the unfavorable change was a $37 million decrease in interest expense. For third-quarter 2017, the cash distribution coverage ratio was 1.17x.

Year-to-date, Williams Partners generated $2.119 billion in DCF attributable to partnership operations, an unfavorable change of $152 million compared with the same period in 2016. DCF for 2017 was reduced by $175 million for the non-cash deferred revenue amortization associated with the previously described contract restructurings. Also contributing to the unfavorable change was a $35 million increase in maintenance capital expenditures. Partially offsetting the unfavorable change was an $83 million decrease in interest expense. The cash distribution coverage for the nine-month reporting period was 1.24x.

Williams Partners recently announced a regular quarterly cash distribution of $0.60 per unit, payable Nov. 10, 2017, to its common unitholders of record at the close of business on Nov. 3, 2017.

CEO Perspective

Alan Armstrong, chief executive officer of Williams Partners’ general partner, made the following comments:

“The large-scale, competitive positions we've established continue to generate long-term value as evidenced once again this quarter as we maintained our strong results with year-to-date Adjusted EBITDA comparable to 2016 results despite the impact of two hurricanes and the sale of over $3 billion in assets. We've substantially reduced our direct exposure to commodities and, as a result, our current businesses' steady growth is being driven by consistent fee-based revenue growth.

“Our strategic focus on natural gas volumes continues to deliver results. So far in 2017, we've placed four of our 'Big 5' Transco expansion projects into service including Gulf Trace, Hillabee Phase 1, Dalton Expansion and New York Bay Expansion with the fifth of the 'Big 5' expansions - the Virginia Southside II project - expected to be placed in service during fourth-quarter 2017. The incremental capacity from the fully-contracted Transco expansion projects going in service so far this year reflects a 25 percent increase in Transco’s design capacity. And, year-to-date, Transco's transportation revenues have increased $74 million, a 7 percent increase over last year.

“Our existing asset footprint and the efficient incremental expansions available to us have also been highlighted in our Northeast G&P and West segments. Our recently announced agreement to expand our services in the

Northeast for our valued customer, Southwestern Energy, showcases how well-positioned our Northeast G&P segment is to serve the growing gas production in the Marcellus and Utica. We are also positioned to capture growth in the Haynesville where in August, we completed the Springridge South plant expansion, and in Wyoming where we are able to bring more volumes onto our Wamsutter system after placing our Chain Lake compressor station into service in October to meet the growing demand of a customer.

“I’m also extremely pleased that even as we continue to deliver on our growth strategy by successfully executing on expansion projects across our operational map, we have strengthened our balance sheet and credit profile, significantly reducing our debt and continued to lower expenses. Year-to-date in 2017, total adjusted SG&A expenses have been reduced by about $40 million when compared to the same period in 2016.”

Business Segment Results

Effective, Jan. 1, 2017, Williams Partners implemented certain changes in its reporting segments as part of an operational realignment. As a result beginning with the reporting of first-quarter 2017 financial results, Williams Partners operations were comprised of the following reportable segments: Atlantic-Gulf, West, Northeast G&P, and NGL & Petchem Services. As of July 7, 2017, following the completed sale of Williams Partners' ownership interest in the Geismar olefins plant on July 6, 2017, the partnership's NGL & Petchem Services segment no longer contained any operating assets.



Amounts in millions	3Q 2017									3Q 2016						YTD 2017									YTD 2016
	Modified EBITDA			Adjust.			Adjusted EBITDA			Modified EBITDA		Adjust.		Adjusted EBITDA		Modified EBITDA			Adjust.			Adjusted EBITDA			Modified EBITDA			Adjust.		Adjusted EBITDA
Atlantic -Gulf		$430			$1			$431			$423		$11		$434		$1,334			$12			$1,346			$1,165			$42		$1,207
West	(615		)	1,041			426			363		70		433		126			1,061			1,187			1,002			255		1,257
Northeast G&P	115			131			246			214		6		220		588			133			721			656			11		667
NGL & Petchem Services	1,084			(1,083		)	1			70		32		102		1,165			(1,092		)	73			(194		)	377		183
Other	(14		)	11			(3		)	—		—		—		(5		)	—			(5		)	—			—		—
Total		$1,000			$101			$1,101			$1,070		$119		$1,189		$3,208			$114			$3,322			$2,629			$685		$3,314

Definitions of modified EBITDA and adjusted EBITDA and schedules reconciling these measures to net income are included in this news release.

Atlantic-Gulf

This segment includes the partnership’s interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 41 percent interest in Constitution (a consolidated entity) which is under development, and a 60 percent equity-method investment in Discovery.

The Atlantic-Gulf segment reported Modified EBITDA of $430 million for third-quarter 2017, compared with $423 million for third-quarter 2016. Adjusted EBITDA decreased by $3 million to $431 million for the same time period. The increase in Modified EBITDA was driven primarily by $46 million increased fee-based revenues from Transco expansion projects brought online. Partially offsetting the increase were $29 million increased O&M expenses primarily associated with Transco's integrity and pipeline maintenance programs. Proportional EBITDA from joint ventures decreased by $11 million. The total unfavorable impact to Atlantic-Gulf in third-quarter 2017 related to hurricanes was over $6 million.

Year-to-date, Atlantic-Gulf reported Modified EBITDA of $1.334 billion, an increase of $169 million over the same nine-month reporting period in 2016. Adjusted EBITDA increased $139 million to $1.346 billion. Fee-based revenues increased $199 million due primarily to higher volumes from Gulfstar One and Transco expansion projects placed in service. Partially offsetting these improvements were $56 million increased O&M expenses due primarily to higher costs associated with Transco’s integrity and pipeline maintenance programs, the segment’s offshore business, and costs associated with several of Transco's expansion projects.

West

This segment includes the partnership’s interstate natural gas pipeline, Northwest Pipeline, and natural gas gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett

Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian basins. This reporting segment also includes an NGL and natural gas marketing business, storage facilities, and an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL. The partnership completed the disposal of its 50 percent equity-method investment in a Delaware Basin gas gathering system in the Mid-Continent region during first-quarter 2017.

The West segment reported Modified EBITDA of ($615) million for third-quarter 2017, compared with $363 million for third-quarter 2016. Adjusted EBITDA decreased by $7 million to $426 million. The unfavorable change in Modified EBITDA was driven primarily by a $1.019 billion impairment of certain gathering operations in the Mid-Continent region. The unfavorable change also includes $11 million in decreased proportional EBITDA from joint ventures, due in part to the partnership's sale of its interests in certain non-operated Delaware Basin assets in first-quarter 2017. Partially offsetting these decreases were $19 million higher fee-based revenues, a $21 million increase in commodity margins and a $12 million decline in O&M and SG&A expenses. Adjusted EBITDA excludes the previously mentioned impairment charge and is further adjusted for estimated minimum volume commitments. As a result, Adjusted EBITDA reflects $33 million of lower fee-based revenues. The West segment also experienced unfavorable impacts from Hurricane Harvey of more than $1 million during third-quarter 2017.

Year-to-date, the West segment reported Modified EBITDA of $126 million, a decrease of $876 million from the same nine-month period in 2016. Adjusted EBITDA decreased by $70 million to $1.187 billion. The unfavorable change in Modified EBITDA reflected the impairment in the Mid-Continent region described in the above paragraph. The unfavorable change also includes $21 million in decreased proportional EBITDA of joint ventures, due in part to the partnership’s sale of its interests in certain non-operated Delaware Basin assets in first-quarter 2017. Partially offsetting the decreases were $59 million in reduced O&M and SG&A expenses and $38 million in improved commodity margins. Revenues reflect an increase from the amortization of deferred revenue from 2016 contract restructurings largely offset by lower rates associated with those restructurings and lower volumes driven by natural declines. Adjusted EBITDA excludes the previously mentioned impairment charge and is further adjusted for estimated minimum volume commitments. As a result, Adjusted EBITDA reflects $141 million of lower fee-based revenues.

Northeast G&P

This segment includes the partnership’s natural gas gathering and processing, compression and NGL fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in UEOM, a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns an approximate average 66 percent equity-method investment in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).

The Northeast G&P segment reported Modified EBITDA of $115 million for third-quarter 2017, compared with $214 million for third-quarter 2016. Adjusted EBITDA increased by $26 million to $246 million. The unfavorable change in Modified EBITDA reflected a $115 million impairment of certain gathering operations in the Marcellus South. This impairment charge is excluded from Adjusted EBITDA. The current year benefited from a $30 million increase in proportional EBITDA of joint ventures due largely to the partnership's increase in ownership in two Marcellus shale gathering systems in first-quarter 2017. Fee-based revenues were stable between the two periods due to increases in the Susquehanna that offset decreases in the Utica.

Year-to-date, the Northeast G&P segment reported Modified EBITDA of $588 million, a decrease of $68 million over the corresponding nine-month period in 2016. Adjusted EBITDA increased by $54 million to $721 million. The unfavorable change in Modified EBITDA reflected the impairment in the Marcellus South region described in the above paragraph. This impairment charge is excluded from Adjusted EBITDA. The current year benefited from a $51 million increase in proportional EBITDA of joint ventures due largely to the previously described increase in ownership in two Marcellus shale gathering systems. Fee-based revenues were stable between the two periods due to increases in the Susquehanna and Ohio River systems that offset decreases in the Utica.

NGL & Petchem Services

On Jan. 1, 2017, this segment included the partnership’s 88.46 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter. On July 6, 2017, the partnership

announced that it had completed the sale of all of its membership interest in the Geismar olefins production facility and associated complex. On June 30, 2017 the partnership completed the sale of the refinery grade propylene splitter. Prior to September 2016, this reporting segment also included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility, which were subsequently sold. As of July 7, 2017, this segment no longer contained any operating assets.

The NGL & Petchem Services segment reported Modified EBITDA of $1.084 billion for third-quarter 2017, compared with $70 million for third-quarter 2016. Adjusted EBITDA decreased by $101 million to $1 million. The improvement in Modified EBITDA was driven primarily by the $1.095 billion gain resulting from the sale of the partnership's interest in the Geismar olefins facility on July 6, 2017. This gain is excluded from Adjusted EBITDA. The current year was also impacted by the absence of EBITDA associated with assets recently sold by the partnership as described in the above paragraph.

Year-to-date, the NGL & Petchem Services segment reported Modified EBITDA of $1.165 billion, an improvement of $1.359 billion over the same nine-month reporting period in 2016. Adjusted EBITDA decreased $110 million to $73 million. The improvement in Modified EBITDA was driven primarily by the $1.095 billion gain resulting from the sale of the partnership's interest in the Geismar olefins facility on July 6, 2017, and the absence of a $341 million impairment of our former Canadian operations in 2016. These items are excluded from Adjusted EBITDA. The current year was also impacted by the absence of EBITDA associated with the previously described assets that were recently sold by the partnership.

Atlantic Sunrise Update

On Sept. 18, 2017 Williams Partners reported that construction is now underway in Pennsylvania on the greenfield portion of the Atlantic Sunrise pipeline project - an expansion of the existing Transco natural gas pipeline to connect abundant Marcellus gas supplies with markets in the Mid-Atlantic and Southeastern U.S. The partnership anticipates pipeline and compressor station construction to last approximately 10 months, weather permitting. Additionally, Williams Partners also placed a portion of the project into early service on Sept. 1, 2017, providing 400,000 dth/day of firm transportation service on Transco's existing mainline facilities to various delivery points as far south as Choctaw County, Alabama. The partial service milestone is the result of recently completed modifications to existing Transco facilities in Virginia and Maryland designed to further accommodate bi-directional flow on the existing Transco pipeline system.

Additional Notable Recent Accomplishments

On Oct. 12, 2017, Williams Partners announced the execution of agreements with Southwestern Energy Company (NYSE: SWN) (“Southwestern”) to expand its services to Southwestern in the Appalachian Basin of West Virginia where Williams Partners has established a strong operational footprint. The agreements call for Williams Partners to deliver gas processing, fractionation, and liquids handling services in Southwestern’s Wet Gas Acreage in the Marcellus and Upper Devonian Shale along with gas gathering services for Southwestern in its South Utica Dry Gas Acreage. Williams Partners will provide Southwestern with 660 million cubic feet per day (MMcf/d) of processing capacity to serve a 135,000-acre dedication in Southwestern’s Wet Gas Acreage in the Marcellus and Upper Devonian Shale in Marshall and Wetzel counties in West Virginia. As a result of this agreement, Williams Partners expects to further build out its Oak Grove processing facility for Southwestern’s expanding production of wet gas. The Oak Grove processing facility has the ability to expand by an additional 1.8 Bcf/d of gas processing capacity.

On Oct. 9, 2017, Williams Partners announced that it has placed into service an expansion of its Transco pipeline system to increase natural gas delivery capacity to New York City by 115,000 dekatherms per day in time for the 2017/2018 heating season. The New York Bay Expansion provides additional firm transportation capacity for much-needed incremental natural gas supplies to National Grid, the largest distributor of natural gas in the northeastern U.S. The company provides service to 1.8 million customers in Brooklyn, Queens, Staten Island and Long Island. The New York Bay Expansion is the fourth of Williams Partners’ projected five fully-contracted Transco expansion projects to be placed into service this year, combining with Gulf Trace, Hillabee Phase 1 and the Dalton Expansion to add more than 2.5 million dekatherms per day capacity to the Transco pipeline system so far in 2017. The partnership continues to target a fourth-quarter 2017 in-service date for its fifth Transco expansion this year - the Virginia Southside II project.

Williams Partners' Credit Profile Improvement including Debt Reduction Update

The partnership continued to strengthen its balance sheet and credit profile during the quarter with nearly $2.1 billion of debt reduction. As of the end of third-quarter 2017, the partnership had total debt of $16.5 billion. Year-to-

date, cash and cash equivalents increased by $1.02 billion to $1.17 billion, which the partnership intends to use primarily to fund growth capital expenditures and long-term investments.

Guidance

The Guidance previously provided at our Analyst Day event on May 11, 2017, remains unchanged. The partnership plans to announce its 2018 Guidance as part of the release of its fourth-quarter 2017 financial results.

Williams Partners’ Third-Quarter 2017 Materials to be Posted Shortly; Q&A Webcast Scheduled for Tomorrow

Williams Partners’ third-quarter 2017 financial results package will be posted shortly at www.williams.com. Note: the analyst package is included at the back of this news release.

Williams Partners and Williams will host a joint Q&A live webcast on Thursday, Nov. 2 at 9:30 a.m. Eastern Time (8:30 a.m. Central Time). A limited number of phone lines will be available at (877) 830-2641. International callers should dial (785) 424-1809. The conference ID is 8089866. The link to the webcast, as well as replays of the webcast, will be available for at least 90 days following the event at www.williams.com.

Form 10-Q

The partnership plans to file its third-quarter 2017 Form 10-Q with the Securities and Exchange Commission (SEC) this week. Once filed, the document will be available on both the SEC and Williams Partners websites.

Definitions of Non-GAAP Measures

This news release may include certain financial measures – Adjusted EBITDA, distributable cash flow and cash distribution coverage ratio – that are non-GAAP financial measures as defined under the rules of the SEC.

Our segment performance measure, Modified EBITDA, is defined as net income (loss) before income tax expense, net interest expense, equity earnings from equity-method investments, other net investing income, impairments of equity investments and goodwill, depreciation and amortization expense, and accretion expense associated with asset retirement obligations for nonregulated operations. We also add our proportional ownership share (based on ownership interest) of Modified EBITDA of equity-method investments.

Adjusted EBITDA further excludes items of income or loss that we characterize as unrepresentative of our ongoing operations. Management believes these measures provide investors meaningful insight into results from ongoing operations.

We define distributable cash flow as Adjusted EBITDA less maintenance capital expenditures, cash portion of interest expense, income attributable to noncontrolling interests and cash income taxes, plus WPZ restricted stock unit non-cash compensation expense and certain other adjustments that management believes affects the comparability of results. Adjustments for maintenance capital expenditures and cash portion of interest expense include our proportionate share of these items of our equity-method investments.

We also calculate the ratio of distributable cash flow to the total cash distributed (cash distribution coverage ratio). This measure reflects the amount of distributable cash flow relative to our cash distribution. We have also provided this ratio using the most directly comparable GAAP measure, net income (loss).

This news release is accompanied by a reconciliation of these non-GAAP financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are accepted financial indicators used by investors to compare company performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of the Partnership's assets and the cash that the business is generating.

Neither Adjusted EBITDA nor distributable cash flow are intended to represent cash flows for the period, nor are they presented as an alternative to net income or cash flow from operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles.

About Williams Partners

Williams Partners is an industry-leading, large-cap natural gas infrastructure master limited partnership with a strong growth outlook and major positions in key U.S. supply basins. Williams Partners has operations across the natural gas value chain including gathering, processing and interstate transportation of natural gas and natural gas liquids. Williams Partners owns and operates more than 33,000 miles of pipelines system wide – including the nation’s largest volume and fastest growing pipeline – providing natural gas for clean-power generation, heating and industrial use. Williams Partners’ operations touch approximately 30 percent of U.S. natural gas. Tulsa, Okla.-based Williams (NYSE: WMB), a premier provider of large-scale U.S. natural gas infrastructure, owns approximately 74 percent of Williams Partners.

Forward-Looking Statements

The reports, filings, and other public announcements of Williams Partners L.P. (WPZ) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters.

All statements, other than statements of historical facts, included herein that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” “assumes,” “guidance,” “outlook,” “in-service date” or other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:


•	Levels of cash distributions with respect to limited partner interests;


•	Our and our affiliates’ future credit ratings;


•	Amounts and nature of future capital expenditures;


•	Expansion and growth of our business and operations;


•	Expected in-service dates for capital projects;


•	Financial condition and liquidity;


•	Business strategy;


•	Cash flow from operations or results of operations;


•	Seasonality of certain business components;


•	Natural gas and natural gas liquids prices, supply, and demand;


•	Demand for our services.

Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied herein. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:


•	Whether we will produce sufficient cash flows to provide expected levels of cash distributions;


•	Whether we elect to pay expected levels of cash distributions;


•	Whether we will be able to effectively execute our financing plan;


•	Whether Williams will be able to effectively manage the transition in its board of directors and management as well as successfully execute its business restructuring;


•	Availability of supplies, including lower than anticipated volumes from third parties served by our business, and market demand;


•	Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins;


•	Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);


•	The strength and financial resources of our competitors and the effects of competition;


•	Whether we are able to successfully identify, evaluate, and timely execute our capital projects and other investment opportunities in accordance with our forecasted capital expenditures budget;


•	Our ability to successfully expand our facilities and operations;


•	Development and rate of adoption of alternative energy sources;


•	The impact of operational and developmental hazards, unforeseen interruptions, and the availability of adequate insurance coverage;


•	The impact of existing and future laws, regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;


•	Our costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;


•	Changes in maintenance and construction costs;


•	Changes in the current geopolitical situation;


•	Our exposure to the credit risk of our customers and counterparties;


•	Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally-recognized credit rating agencies and the availability and cost of capital;


•	The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;


•	Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;


•	Acts of terrorism, including cybersecurity threats, and related disruptions;


•	Additional risks described in our filings with the Securities and Exchange Commission (SEC).

Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

In addition to causing our actual results to differ, the factors listed above may cause our intentions to change from those statements of intention set forth herein. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.

Limited partner units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the risk factors discussed above in addition to the other information contained herein. If any of such risks were actually to occur, our business, results of operations, and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment.

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February 22, 2017.

# # #






	Non-GAAP Reconciliations,
	Financial Highlights, and Operating Statistics

	(UNAUDITED)

	Final

	September 30, 2017

Williams Partners L.P.

Reconciliation of Non-GAAP Measures

(UNAUDITED)



	2016															2017
(Dollars in millions, except coverage ratios)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			Year

Williams Partners L.P.
Reconciliation of "Net Income (Loss)" to "Modified EBITDA", Non-GAAP "Adjusted EBITDA" and "Distributable cash flow"

Net income (loss)	$	79		$	(77	)	$	351		$	166		$	519		$	660		$	348		$	284		$	1,292
Provision (benefit) for income taxes	1			(80		)	(6		)	5			(80		)	3			1			(1		)	3
Interest expense	229			231			229			227			916			214			205			202			621
Equity (earnings) losses	(97		)	(101		)	(104		)	(95		)	(397		)	(107		)	(125		)	(115		)	(347		)
Impairment of equity-method investments	112			—			—			318			430			—			—			—			—
Other investing (income) loss	—			(1		)	(28		)	—			(29		)	(271		)	(2		)	(4		)	(277		)
Proportional Modified EBITDA of equity-method investments	189			191			194			180			754			194			215			202			611
Depreciation and amortization expenses	435			432			426			427			1,720			433			423			424			1,280
Accretion for asset retirement obligations associated with nonregulated operations	7			9			8			7			31			6			11			8			25
Modified EBITDA	955			604			1,070			1,235			3,864			1,132			1,076			1,000			3,208

Adjustments
Estimated minimum volume commitments	60			64			70			(194		)	—			15			15			18			48
Severance and related costs	25			—			—			12			37			9			4			5			18
Potential rate refunds associated with rate case litigation	15			—			—			—			15			—			—			—			—
ACMP Merger and transition costs	5			—			—			—			5			—			4			3			7
Constitution Pipeline project development costs	—			8			11			9			28			2			6			4			12
Share of impairment at equity-method investment	—			—			6			19			25			—			—			1			1
Geismar Incident adjustment	—			—			—			(7		)	(7		)	(9		)	2			8			1
Gain on sale of Geismar Interest	—			—			—			—			—			—			—			(1,095		)	(1,095		)
Impairment of certain assets	—			389			—			22			411			—			—			1,142			1,142
Ad valorem obligation timing adjustment	—			—			—			—			—			—			—			7			7
Organizational realignment-related costs	—			—			—			24			24			4			6			6			16
Loss related to Canada disposition	—			—			32			2			34			(3		)	(1		)	4			—
Gain on asset retirement	—			—			—			(11		)	(11		)	—			—			(5		)	(5		)
Gains from contract settlements and terminations	—			—			—			—			—			(13		)	(2		)	—			(15		)
Accrual for loss contingency	—			—			—			—			—			9			—			—			9
Gain on early retirement of debt	—			—			—			—			—			(30		)	—			3			(27		)
Gain on sale of RGP Splitter	—			—			—			—			—			—			(12		)	—			(12		)
Expenses associated with Financial Repositioning	—			—			—			—			—			—			2			—			2
Expenses associated with strategic asset monetizations	—			—			—			2			2			1			4			—			5
Total EBITDA adjustments	105			461			119			(122		)	563			(15		)	28			101			114
Adjusted EBITDA	1,060			1,065			1,189			1,113			4,427			1,117			1,104			1,101			3,322

Maintenance capital expenditures ⁽¹⁾	(58		)	(75		)	(121		)	(147		)	(401		)	(53		)	(100		)	(136		)	(289		)
Interest expense (cash portion) ⁽²⁾	(241		)	(245		)	(244		)	(239		)	(969		)	(224		)	(216		)	(207		)	(647		)
Cash taxes	—			—			—			(3		)	(3		)	(5		)	(1		)	(4		)	(10		)
Income attributable to noncontrolling interests ⁽³⁾	(29		)	(13		)	(31		)	(27		)	(100		)	(27		)	(32		)	(27		)	(86		)
WPZ restricted stock unit non-cash compensation	7			5			2			2			16			2			1			1			4
Amortization of deferred revenue associated with certain 2016 contract restructurings	—			—			—			—			—			(58		)	(58		)	(59		)	(175		)

Distributable cash flow attributable to Partnership Operations ⁽⁴⁾	739			737			795			699			2,970			752			698			669			2,119

Total cash distributed ⁽⁵⁾	$	725		$	725		$	734		$	762		$	2,946		$	567		$	574		$	574		$	1,715

Coverage ratios:
Distributable cash flow attributable to partnership operations divided by Total cash distributed	1.02			1.02			1.08			0.92			1.01			1.33			1.22			1.17			1.24

Net income (loss) divided by Total cash distributed	0.11			(0.11		)	0.48			0.22			0.18			1.16			0.61			0.49			0.75

(1) Includes proportionate share of maintenance capital expenditures of equity investments.
(2) Includes proportionate share of interest expense of equity investments.
(3) Excludes allocable share of certain EBITDA adjustments.
(4) The fourth quarter of 2016 includes income of $183 million associated with proceeds from the contract restructuring in the Barnett Shale and Mid-Continent region as the cash was received during 2016.
(5) In order to exclude the impact of the IDR waiver associated with the WPZ merger termination fee from the determination of coverage ratios, cash distributions have been increased by $10 million in the first quarter of 2016. Cash distributions for the third quarter of 2016 have been increased to exclude the impact of the $150 million IDR waiver associated with the sale of our Canadian operations. Cash distributions for the fourth quarter of 2016 and the first quarter of 2017 have been decreased by $50 million and $6 million, respectively, to reflect the amount paid by WMB to WPZ pursuant to the January 2017 Common Unit Purchase Agreement.

Williams Partners L.P.

Reconciliation of “Modified EBITDA” to Non-GAAP “Adjusted EBITDA”

(UNAUDITED)



	2016													2017
(Dollars in millions)	1st Qtr		2nd Qtr			3rd Qtr		4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			Year

Modified EBITDA:
Northeast G&P	$	220	$	222		$	214	$	197		$	853		$	226		$	247		$	115		$	588
Atlantic-Gulf	382		360			423		456			1,621			450			454			430			1,334
West	327		312			363		542			1,544			385			356			(615		)	126
NGL & Petchem Services	26		(290		)	70		49			(145		)	51			30			1,084			1,165
Other	—		—			—		(9		)	(9		)	20			(11		)	(14		)	(5		)
Total Modified EBITDA	$	955	$	604		$	1,070	$	1,235		$	3,864		$	1,132		$	1,076		$	1,000		$	3,208

Adjustments:
Northeast G&P
Severance and related costs	$	3	$	—		$	—	$	—		$	3		$	—		$	—		$	—		$	—
Share of impairment at equity-method investments	—		—			6		19			25			—			—			1			1
ACMP Merger and transition costs	2		—			—		—			2			—			—			—			—
Impairment of certain assets	—		—			—		—			—			—			—			121			121
Ad valorem obligation timing adjustment	—		—			—		—			—			—			—			7			7
Organizational realignment-related costs	—		—			—		3			3			1			1			2			4
Total Northeast G&P adjustments	5		—			6		22			33			1			1			131			133
Atlantic-Gulf
Potential rate refunds associated with rate case litigation	15		—			—		—			15			—			—			—			—
Severance and related costs	8		—			—		—			8			—			—			—			—
Constitution Pipeline project development costs	—		8			11		9			28			2			6			4			12
Organizational realignment-related costs	—		—			—		—			—			1			2			2			5
Gain on asset retirement	—		—			—		(11		)	(11		)	—			—			(5		)	(5		)
Total Atlantic-Gulf adjustments	23		8			11		(2		)	40			3			8			1			12
West
Estimated minimum volume commitments	60		64			70		(194		)	—			15			15			18			48
Severance and related costs	10		—			—		3			13			—			—			—			—
ACMP Merger and transition costs	3		—			—		—			3			—			—			—			—
Impairment of certain assets	—		48			—		22			70			—			—			1,021			1,021
Organizational realignment-related costs	—		—			—		21			21			2			3			2			7
Gains from contract settlements and terminations	—		—			—		—			—			(13		)	(2		)	—			(15		)
Total West adjustments	73		112			70		(148		)	107			4			16			1,041			1,061
NGL & Petchem Services
Impairment of certain assets	—		341			—		—			341			—			—			—			—
Loss related to Canada disposition	—		—			32		2			34			(3		)	(1		)	4			—
Severance and related costs	4		—			—		—			4			—			—			—			—
Expenses associated with strategic asset monetizations	—		—			—		2			2			1			4			—			5
Geismar Incident adjustments	—		—			—		(7		)	(7		)	(9		)	2			8			1
Gain on sale of Geismar Interest	—		—			—		—			—			—			—			(1,095		)	(1,095		)
Gain on sale of RGP Splitter	—		—			—		—			—			—			(12		)				(12		)
Accrual for loss contingency	—		—			—		—			—			9			—			—			9
Total NGL & Petchem Services adjustments	4		341			32		(3		)	374			(2		)	(7		)	(1,083		)	(1,092		)
Other
Severance and related costs	—		—			—		9			9			9			4			5			18
ACMP Merger and transition costs	—		—			—		—			—			—			4			3			7
Expenses associated with Financial Repositioning	—		—			—		—			—			—			2			—			2
Gain on early retirement of debt	—		—			—		—			—			(30		)	—			3			(27		)
Total Other adjustments	—		—			—		9			9			(21		)	10			11			—

Total Adjustments	$	105	$	461		$	119	$	(122	)	$	563		$	(15	)	$	28		$	101		$	114

Adjusted EBITDA:
Northeast G&P	$	225	$	222		$	220	$	219		$	886		$	227		$	248		$	246		$	721
Atlantic-Gulf	405		368			434		454			1,661			453			462			431			1,346
West	400		424			433		394			1,651			389			372			426			1,187
NGL & Petchem Services	30		51			102		46			229			49			23			1			73
Other	—		—			—		—			—			(1		)	(1		)	(3		)	(5		)
Total Adjusted EBITDA	$	1,060	$	1,065		$	1,189	$	1,113		$	4,427		$	1,117		$	1,104		$	1,101		$	3,322

Williams Partners L.P.

Consolidated Statement of Income (Loss)

(UNAUDITED)



	2016															2017
(Dollars in millions, except per-unit amounts)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			Year

Revenues:
Service revenues	$	1,226		$	1,210		$	1,252		$	1,485		$	5,173		$	1,256		$	1,277		$	1,304		$	3,837
Product sales	428			530			655			705			2,318			727			642			581			1,950
Total revenues	1,654			1,740			1,907			2,190			7,491			1,983			1,919			1,885			5,787
Costs and expenses:
Product costs	317			403			463			545			1,728			579			537			504			1,620
Operating and maintenance expenses	382			386			385			395			1,548			361			384			396			1,141
Depreciation and amortization expenses	435			432			426			427			1,720			433			423			424			1,280
Selling, general, and administrative expenses	181			139			147			163			630			156			154			140			450
Gain on sale of Geismar Interest	—			—			—			—			—			—			—			(1,095		)	(1,095		)
Impairment of certain assets	6			396			1			54			457			1			2			1,142			1,145
Other (income) expense - net	24			24			59			4			111			3			7			22			32
Total costs and expenses	1,345			1,780			1,481			1,588			6,194			1,533			1,507			1,533			4,573
Operating income (loss)	309			(40		)	426			602			1,297			450			412			352			1,214
Equity earnings (losses)	97			101			104			95			397			107			125			115			347
Impairment of equity-method investments	(112		)	—			—			(318		)	(430		)	—			—			—			—
Other investing income (loss) - net	—			1			28			—			29			271			2			4			277
Interest incurred	(240		)	(239		)	(236		)	(234		)	(949		)	(221		)	(214		)	(210		)	(645		)
Interest capitalized	11			8			7			7			33			7			9			8			24
Other income (expense) - net	15			12			16			19			62			49			15			14			78
Income (loss) before income taxes	80			(157		)	345			171			439			663			349			283			1,295
Provision (benefit) for income taxes	1			(80		)	(6		)	5			(80		)	3			1			(1		)	3
Net income (loss)	79			(77		)	351			166			519			660			348			284			1,292
Less: Net income attributable to noncontrolling interests	29			13			25			21			88			26			28			25			79
Net income (loss) attributable to controlling interests	$	50		$	(90	)	$	326		$	145		$	431		$	634		$	320		$	259		$	1,213

Allocation of net income (loss) for calculation of earnings per common unit:
Net income (loss) attributable to controlling interests	$	50		$	(90	)	$	326		$	145		$	431		$	634		$	320		$	259		$	1,213
Allocation of net income (loss) to general partner ⁽¹⁾	202			207			72			—			517			—			—			—			—
Allocation of net income (loss) to Class B units ⁽¹⁾	(4		)	(8		)	7			2			12			11			6			4			21
Allocation of net income (loss) to common units ⁽¹⁾	$	(148	)	$	(289	)	$	247		$	143		$	(98	)	$	623		$	314		$	255		$	1,192

Diluted earnings (loss) per common unit:
Net income (loss) per common unit ⁽¹⁾	$	(0.25	)	$	(0.49	)	$	0.42		$	0.24		$	(0.17	)	$	0.68		$	0.33		$	0.27		$	1.26
Weighted average number of common units outstanding (thousands)	588,562			588,607			591,567			601,738			592,519			920,250			955,986			956,365			944,333

Cash distributions per common unit	$	0.85		$	0.85		$	0.85		$	0.85		$	3.40		$	0.60		$	0.60		$	0.60		$	1.80

(1) The sum for the quarters may not equal the total for the year due to timing of unit issuances.

Williams Partners L.P.

Northeast G&P

(UNAUDITED)



	2016															2017
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			Year

Revenues:
Service revenues:
Nonregulated gathering and processing fee-based revenue	$	186		$	182		$	179		$	184		$	731		$	182		$	183		$	182		$	547
Other fee revenues	37			40			39			42			158			40			38			36			114
Product sales:
NGL sales from gas processing	4			3			3			4			14			4			4			2			10
Marketing sales	19			31			40			58			148			64			48			59			171
	246			256			261			288			1,051			290			273			279			842
Intrasegment eliminations	(4		)	(6		)	(4		)	(5		)	(19		)	(5		)	(4		)	(4		)	(13		)
Total revenues	242			250			257			283			1,032			285			269			275			829

Segment costs and expenses:
NGL cost of goods sold	1			2			1			2			6			4			1			2			7
Marketing cost of goods sold	20			32			41			60			153			65			48			59			172
Other segment costs and expenses ⁽¹⁾	99			91			95			98			383			91			93			102			286
Impairment of certain assets	4			4			—			5			13			1			1			121			123
Intrasegment eliminations	(4		)	(6		)	(4		)	(5		)	(19		)	(5		)	(4		)	(4		)	(13		)
Total segment costs and expenses	120			123			133			160			536			156			139			280			575

Proportional Modified EBITDA of equity-method investments	98			95			90			74			357			97			117			120			334
Modified EBITDA	220			222			214			197			853			226			247			115			588
Adjustments	5			—			6			22			33			1			1			131			133
Adjusted EBITDA	$	225		$	222		$	220		$	219		$	886		$	227		$	248		$	246		$	721

Statistics for Operated Assets

Gathering and Processing
Gathering volumes (Bcf per day) - Consolidated ⁽²⁾	3.34			3.15			3.16			3.19			3.21			3.32			3.28			3.28			3.29
Gathering volumes (Bcf per day) - Non-consolidated ⁽³⁾	3.21			3.16			3.08			3.20			3.16			3.55			3.58			3.48			3.54
Plant inlet natural gas volumes (Bcf per day) ⁽²⁾	0.31			0.31			0.34			0.37			0.33			0.39			0.40			0.45			0.41

Ethane equity sales (Mbbls/d)	6			4			3			3			4			2			2			2			2
Non-ethane equity sales (Mbbls/d)	1			1			1			1			1			1			1			1			1
NGL equity sales (Mbbls/d)	7			5			4			4			5			3			3			3			3

Ethane production (Mbbls/d)	14			18			22			20			18			17			22			17			19
Non-ethane production (Mbbls/d)	11			12			16			15			14			15			17			19			17
NGL production (Mbbls/d)	25			30			38			35			32			32			39			36			36

(1) Includes operating expenses, general and administrative expenses, and other income or expenses.
(2) Includes gathering volumes associated with Susquehanna Supply Hub, Ohio Valley Midstream, and Utica Supply Hub, all of which are consolidated.
(3) Includes 100% of the volumes associated with operated equity-method investments, including the Laurel Mountain Midstream partnership; and the Bradford Supply Hub and a portion of the Marcellus South Supply Hub within the Appalachia Midstream Services partnership. Volumes handled by Blue Racer Midstream (gathering and processing) and UEOM (processing only), which we do not operate, are not included.

Williams Partners L.P.

Atlantic-Gulf

(UNAUDITED)



	2016															2017
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			Year

Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue	$	92		$	76		$	131		$	137		$	436		$	127		$	136		$	133		$	396
Regulated transportation revenue	349			331			339			348			1,367			354			358			381			1,093
Other fee revenues	24			41			41			42			148			54			42			38			134
Product sales:
NGL sales from gas processing	8			11			24			31			74			27			16			13			56
Marketing sales	45			75			78			84			282			90			75			66			231
Other sales	—			—			4			4			8			1			—			1			2
Tracked revenues	38			39			51			39			167			36			52			47			135
	556			573			668			685			2,482			689			679			679			2,047
Intrasegment eliminations	(9		)	(10		)	(9		)	(6		)	(34		)	(19		)	(7		)	(9		)	(35		)
Total revenues	547			563			659			679			2,448			670			672			670			2,012

Segment costs and expenses:
NGL cost of goods sold	3			4			15			15			37			13			7			6			26
Marketing cost of goods sold	45			74			78			83			280			88			75			65			228
Other cost of goods sold	—			—			2			1			3			—			—			—			—
Impairment of certain assets	1			2			—			—			3			—			—			—			—
Other segment costs and expenses ⁽¹⁾	153			162			174			169			658			174			171			195			540
Tracked costs	38			39			51			39			167			36			52			47			135
Intrasegment eliminations	(9		)	(10		)	(9		)	(6		)	(34		)	(19		)	(7		)	(9		)	(35		)
Total segment costs and expenses	231			271			311			301			1,114			292			298			304			894

Proportional Modified EBITDA of equity-method investments	66			68			75			78			287			72			80			64			216
Modified EBITDA	382			360			423			456			1,621			450			454			430			1,334
Adjustments	23			8			11			—			42			3			8			1			12
Adjusted EBITDA	$	405		$	368		$	434		$	456		$	1,663		$	453		$	462		$	431		$	1,346

Statistics for Operated Assets
Gathering, Processing and Crude Oil Transportation
Gathering volumes (Bcf per day) - Consolidated ⁽²⁾	0.30			0.30			0.52			0.53			0.41			0.32			0.29			0.31			0.31
Gathering volumes (Bcf per day) - Non-consolidated ⁽³⁾	0.53			0.54			0.60			0.60			0.56			0.55			0.54			0.39			0.49
Plant inlet natural gas volumes (Bcf per day) - Consolidated ⁽²⁾	0.64			0.60			0.84			0.78			0.72			0.56			0.57			0.52			0.55
Plant inlet natural gas volumes (Bcf per day) - Non-consolidated ⁽³⁾	0.56			0.54			0.60			0.60			0.57			0.54			0.53			0.39			0.49

Crude transportation volumes (Mbbls/d)	98			99			126			128			113			131			135			137			134

Consolidated ⁽²⁾
Ethane margin ($/gallon)	$	.03		$	.05		$	(.03	)	$	(.01	)	$	—		$	.02		$	.03		$	.04		$	.03
Non-ethane margin ($/gallon)	$	.30		$	.38		$	.26		$	.35		$	.31		$	.42		$	.36		$	.53		$	.42
NGL margin ($/gallon)	$	.21		$	.18		$	.16		$	.20		$	.19		$	.26		$	.23		$	.26		$	.25

Ethane equity sales (Mbbls/d)	2			6			6			8			5			6			4			4			5
Non-ethane equity sales (Mbbls/d)	4			4			11			12			8			9			6			3			6
NGL equity sales (Mbbls/d)	6			10			17			20			13			15			10			7			11

Ethane production (Mbbls/d)	13			17			16			19			16			14			14			13			14
Non-ethane production (Mbbls/d)	20			20			31			30			25			20			19			18			19
NGL production (Mbbls/d)	33			37			47			49			41			34			33			31			33

Non-consolidated ⁽³⁾
NGL equity sales (Mbbls/d)	5			5			5			5			5			5			4			5			5
NGL production (Mbbls/d)	17			19			21			21			20			21			22			22			22

Transcontinental Gas Pipe Line
Throughput (Tbtu)	927.2			815.9			878.1			881.5			3,502.7			939.1			887.6			938.5			2,765.2
Avg. daily transportation volumes (Tbtu)	10.2			9.0			9.5			9.6			9.6			10.4			9.8			10.2			10.1
Avg. daily firm reserved capacity (Tbtu)	12.0			11.5			11.6			11.9			11.7			12.8			13.2			14.1			13.4

(1) Includes operating expenses, general and administrative expenses, and other income or expenses.
(2) Excludes volumes associated with equity-method investments that are not consolidated in our results.
(3) Includes 100% of the volumes associated with operated equity-method investments.

Williams Partners L.P.

West

(UNAUDITED)



	2016															2017
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			Year

Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue	$	376		$	379		$	374		$	593		$	1,722		$	364		$	382		$	398		$	1,144
Regulated transportation revenue	118			111			114			117			460			117			112			113			342
Other fee revenues	42			44			43			44			173			43			38			39			120
Product sales:
NGL sales from gas processing	38			54			53			58			203			64			61			68			193
Olefin sales	—			—			—			—			—			1			—			—			1
Marketing sales	269			342			396			504			1,511			506			490			561			1,557
Other sales	6			4			5			4			19			6			8			12			26
Tracked revenues	—			1			—			—			1			—			1			—			1
	849			935			985			1,320			4,089			1,101			1,092			1,191			3,384
Intrasegment eliminations	(76		)	(101		)	(95		)	(109		)	(381		)	(127		)	(130		)	(162		)	(419		)
Total revenues	773			834			890			1,211			3,708			974			962			1,029			2,965

Segment costs and expenses:
NGL cost of goods sold	18			22			26			25			91			27			31			31			89
Marketing cost of goods sold	271			345			396			494			1,506			505			498			550			1,553
Other cost of goods sold	5			3			5			3			16			5			4			12			21
Other segment costs and expenses ⁽¹⁾	252			231			223			235			941			204			220			209			633
Impairment of certain assets	1			49			1			49			100			—			1			1,021			1,022
Tracked costs	—			1			—			—			1			—			—			1			1
Intrasegment eliminations	(76		)	(101		)	(95		)	(109		)	(381		)	(127		)	(130		)	(162		)	(419		)
Total segment costs and expenses	471			550			556			697			2,274			614			624			1,662			2,900

Proportional Modified EBITDA of equity-method investments	25			28			29			28			110			25			18			18			61
Modified EBITDA	327			312			363			542			1,544			385			356			(615		)	126
Adjustments	73			112			70			(148		)	107			4			16			1,041			1,061
Adjusted EBITDA	$	400		$	424		$	433		$	394		$	1,651		$	389		$	372		$	426		$	1,187

Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day)	4.60			4.68			4.72			4.50			4.62			4.23			4.40			4.62			4.42
Plant inlet natural gas volumes (Bcf per day)	2.51			2.51			2.48			2.32			2.45			1.99			2.00			2.11			2.03

Ethane equity sales (Mbbls/d)	4			15			6			4			7			3			11			11			8
Non-ethane equity sales (Mbbls/d)	20			22			23			21			21			20			20			20			20
NGL equity sales (Mbbls/d)	24			37			29			25			28			23			31			31			28

Ethane margin ($/gallon)	$	.03		$	.00		$	.00		$	.00		$	.01		$	.04		$	.00		$	.02		$	.02
Non-ethane margin ($/gallon)	$	.26		$	.39		$	.31		$	.41		$	.34		$	.49		$	.40		$	.45		$	.45
NGL margin ($/gallon)	$	.22		$	.23		$	.24		$	.34		$	.26		$	.43		$	.26		$	.30		$	.32

Ethane production (Mbbls/d)	12			25			10			9			14			8			18			19			15
Non-ethane production (Mbbls/d)	64			66			65			62			64			55			57			62			58
NGL production (Mbbls/d)	76			91			75			71			78			63			75			81			73

Northwest Pipeline LLC
Throughput (Tbtu)	205.6			168.0			161.9			191.6			727.1			219.0			165.4			156.4			540.8
Avg. daily transportation volumes (Tbtu)	2.3			1.8			1.8			2.1			2.0			2.4			1.8			1.7			2.0
Avg. daily firm reserved capacity (Tbtu)	3.0			3.0			3.0			3.0			3.0			3.0			3.0			3.0			3.0

Overland Pass Pipeline Company LLC (equity investment) - 100%
NGL Transportation volumes (Mbbls)	16,814			18,410			18,535			18,078			71,837			18,338			20,558			21,015			59,911

(1) Includes operating expenses, general and administrative expenses, and other income or expenses.

Williams Partners L.P.

NGL & Petchem Services

(UNAUDITED)



	2016															2017
(Dollars in millions)	1st Qtr			2nd Qtr			3rd Qtr			4th Qtr			Year			1st Qtr			2nd Qtr			3rd Qtr			Year

Revenues:
Service revenue:
Nonregulated gathering & processing fee-based revenue	$	1		$	4		$	—		$	—		$	5		$	—		$	—		$	—		$	—
Other fee-based revenues	7			19			14			3			43			3			4			—			7
Product sales:
NGL sales from gas processing	17			3			16			—			36			—			—			—			—
Olefin sales	136			151			202			160			649			160			145			6			311
Marketing sales	28			27			45			39			139			56			38			3			97
Other sales	—			—			2			—			2			—			—			—			—
	189			204			279			202			874			219			187			9			415
Intrasegment eliminations	(13		)	(8		)	(21		)	(5		)	(47		)	(17		)	(26		)	—			(43		)
Total revenues	176			196			258			197			827			202			161			9			372

Segment costs and expenses:
NGL cost of goods sold	12			2			10			—			24			—			—			—			—
Olefins cost of goods sold	65			77			84			86			312			89			93			4			186
Marketing cost of goods sold	28			29			41			40			138			52			40			3			95
Other cost of goods sold	1			—			2			—			3			—			—			—			—
Gain on sale of Geismar Interest	—			—			—			—			—			—			—			(1,095		)	(1,095		)
Impairment of certain assets	—			341			—			1			342			—			—			—			—
Other segment costs and expenses ⁽¹⁾	57			45			72			26			200			27			24			13			64
Intrasegment eliminations	(13		)	(8		)	(21		)	(5		)	(47		)	(17		)	(26		)	—			(43		)
Total segment costs and expenses	150			486			188			148			972			151			131			(1,075		)	(793		)

Modified EBITDA	26			(290		)	70			49			(145		)	51			30			1,084			1,165
Adjustments	4			341			32			(3		)	374			(2		)	(7		)	(1,083		)	(1,092		)
Adjusted EBITDA	$	30		$	51		$	102		$	46		$	229		$	49		$	23		$	1		$	73

Statistics for Operated Assets

Ethane equity sales (Mbbls/d)	10			1			8			—			7			—			—			—			—
Non-ethane equity sales (Mbbls/d)	10			1			6			—			6			—			—			—			—
NGL equity sales (Mbbls/d)	20			2			14			—			13			—			—			—			—

Ethane production (Mbbls/d)	10			1			8			—			—			—			—			—			—
Non-ethane production (Mbbls/d)	8			2			8			—			—			—			—			—			—
NGL production (Mbbls/d)	18			3			16			—			—			—			—			—			—

Petrochemical Services
Geismar ethylene sales volumes (million lbs)	423			391			419			405			1,638			266			300			—			566
Geismar ethylene margin ($/lb) ⁽²⁾	$	.13		$	.15		$	.21		$	.15		$	.16		$	.19		$	.13		$	—		$	.16
Canadian propylene sales volumes (millions lbs)	33			8			46			—			87			—			—			—			—
Canadian alky feedstock sales volumes (million gallons)	7			2			6			—			15			—			—			—			—

(1) Includes operating expenses, general and administrative expenses, and other income or expenses.
(2) Ethylene margin and ethylene margin per pound are calculated using financial results determined in accordance with GAAP, which include realized ethylene sales prices and ethylene COGS. Realized sales and COGS per unit metrics may vary from publicly quoted market indices or spot prices due to various factors, including, but not limited to, basis differentials, transportation costs, contract provisions, and inventory accounting methods.

Williams Partners L.P.

Capital Expenditures and Investments

(UNAUDITED)



	2016												2017
(Dollars in millions)	1st Qtr			2nd Qtr		3rd Qtr			4th Qtr		Year		1st Qtr			2nd Qtr			3rd Qtr			Year

Capital expenditures:
Northeast G&P	$	67		$	55	$	46		$	56	$	224	$	58		$	81		$	173		$	312
Atlantic-Gulf	300			410		380			345		1,435		388			398			371			1,157
West	62			33		63			70		228		57			58			94			209
NGL & Petchem Services	34			18		4			1		57		6			1			(1		)	6
Other	—			2		(2		)	—		—		—			2			1			3
Total ⁽¹⁾	$	463		$	518	$	491		$	472	$	1,944	$	509		$	540		$	638		$	1,687

Purchases of investments:
Northeast G&P	$	24		$	40	$	(16	)	$	24	$	72	$	20		$	26		$	24		$	70
Atlantic-Gulf	—			—		—			—		—		—			1			—			1
West	39			19		26			21		105		32			—			—			32
Total	$	63		$	59	$	10		$	45	$	177	$	52		$	27		$	24		$	103

Summary:
Northeast G&P	$	91		$	95	$	30		$	80	$	296	$	78		$	107		$	197		$	382
Atlantic-Gulf	300			410		380			345		1,435		388			399			371			1,158
West	101			52		89			91		333		89			58			94			241
NGL & Petchem Services	34			18		4			1		57		6			1			(1		)	6
Other	—			2		(2		)	—		—		—			2			1			3
Total	$	526		$	577	$	501		$	517	$	2,121	$	561		$	567		$	662		$	1,790

Capital expenditures incurred and purchases of investments:
Increases to property, plant, and equipment	$	498		$	485	$	446		$	442	$	1,871	$	569		$	586		$	660		$	1,815
Purchases of investments	63			59		10			45		177		52			27			24			103
Total	$	561		$	544	$	456		$	487	$	2,048	$	621		$	613		$	684		$	1,918

⁽¹⁾ Increases to property, plant, and equipment	$	498		$	485	$	446		$	442	$	1,871	$	569		$	586		$	660		$	1,815
Changes in related accounts payable and accrued liabilities	(35		)	33		45			30		73		(60		)	(46		)	(22		)	(128		)
Capital expenditures	$	463		$	518	$	491		$	472	$	1,944	$	509		$	540		$	638		$	1,687

Selected Financial Information

(UNAUDITED)



	2016								2017
(Dollars in millions)	1st Qtr		2nd Qtr		3rd Qtr		4th Qtr		1st Qtr		2nd Qtr		3rd Qtr

Cash and cash equivalents	$	125	$	101	$	68	$	145	$	625	$	1,908	$	1,165

Capital structure:
Debt:
Commercial paper	$	135	$	196	$	2	$	93	$	—	$	—	$	—
Current	$	976	$	786	$	785	$	785	$	—	$	1,951	$	502
Noncurrent	$	18,504	$	19,116	$	18,918	$	17,685	$	17,065	$	16,614	$	16,000

WILLIAMS PARTNERS L.P. - FORM 8-K - EX-99.1 - November 1, 2017

Attached files

WILLIAMS PARTNERS L.P. Reports