Exhibit 99.1

 

DATE: Aug. 2, 2017

 

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

Williams Partners Reports Second-Quarter 2017 Financial Results

 

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2Q 2017 Net Income of $320 Million

 

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2Q 2017 Adjusted EBITDA of $1.104 Billion, Up $39 Million

 

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2Q 2017 Cash Distribution Coverage Ratio of 1.22x

 

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Placed 3 Transco Expansions (Dalton Expansion, Hillabee Phase 1 and Gulf Trace) Into Service So Far in 2017

 

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On July 6, 2017, Completed Sale of Its Interests in Geismar Plant for $2.1 Billion in Cash; Entered into Long-Term Supply and Transportation Agreements with Plant Buyer

 

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Geismar Sale Proceeds Used to Pay Off $850 Million Term Loan and Prefund a Portion of Growth Capex

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

 

Summary Financial Information		2Q								YTD
Amounts in millions, except per-unit amounts. Per unit amounts are reported on a diluted basis. All amounts are attributable to Williams Partners L.P.		2017				2016				2017				2016
GAAP Measures
Cash Flow from Operations		$	776			$	742			$	1,507			$	1,666
Net income (loss)		$	320			($	90	)		$	954			($	40	)
Net income (loss) per common unit		$	0.33			($	0.49	)		$	1.00			($	0.74	)
Non-GAAP Measures (1)
Adjusted EBITDA		$	1,104			$	1,065			$	2,221			$	2,125
DCF attributable to partnership operations		$	698			$	737			$	1,450			$	1,476
Cash distribution coverage ratio			1.22x				1.02x				1.27x				1.02x

 

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

Second-Quarter 2017 Financial Results

Williams Partners reported unaudited second-quarter 2017 net income attributable to controlling interests of $320 million, a $410 million improvement over second-quarter 2016. The favorable change was driven by a $452 million improvement in

 

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operating income primarily reflecting a $394 million decrease in impairments of certain assets and increased fee-based revenue from expansion projects. The decrease in impairments includes the absence of a second-quarter 2016, $341 million impairment charge associated with the partnership’s now former Canadian business that was sold in September 2016.

Year-to-date, Williams Partners reported unaudited net income of $954 million, a $994 million improvement over the same period in 2016. The favorable change was driven by a $593 million improvement in operating income primarily reflecting a $399 million decrease in impairments of certain assets and increased fee-based revenue from expansion projects. The decrease in impairments includes the absence of the impairment charge referenced above. The improvement in net income also reflects a gain of $269 million associated with the disposition of certain equity-method investments in 2017 and the absence of $112 million of impairments of equity-method investments incurred in 2016.

Williams Partners reported second-quarter 2017 Adjusted EBITDA of $1.104 billion, a $39 million increase over second-quarter 2016. The improvement is due primarily to $18 million increased fee-based revenues and a $24 million increase in proportional EBITDA of joint ventures. Partially offsetting these increases were $22 million lower olefins margins.

Year-to-date, Williams Partners reported Adjusted EBITDA of $2.221 billion, an increase of $96 million over the same six-month reporting period in 2016. The increase is due primarily to $36 million lower operating and maintenance (O&M) and selling, general and administrative (SG&A) expenses, a $28 million improvement in other income and expense, and a $29 million increase in proportional EBITDA of joint ventures.

Distributable Cash Flow and Distributions

For second-quarter 2017, Williams Partners generated $698 million in distributable cash flow (DCF) attributable to partnership operations, compared with $737 million in DCF attributable to partnership operations for second-quarter 2016. DCF for second-quarter 2017 has been reduced by $58 million for the planned removal of non-cash deferred revenue amortization associated with the fourth-quarter 2016 contract restructuring in the Barnett Shale and Mid-Continent region. Also impacting the unfavorable change were $25 million increased maintenance capital expenditures and a $19 million increase in income attributable to non-controlling interests. Partially offsetting the unfavorable changes was the previously described improvement in the quarter’s Adjusted EBITDA and a $29 million decrease in interest expense. For second-quarter 2017, the cash distribution coverage ratio was 1.22x.

Year-to-date, Williams Partners generated $1.450 billion in DCF, a decrease of $26 million over the same period in 2016. DCF for 2017 has been reduced by $116 million for the planned removal of non-cash deferred revenue amortization associated with the fourth-quarter 2016 contract restructuring in the Barnett Shale and Mid-Continent region. Also impacting the unfavorable change were $20 million increased maintenance capital expenditures and a $17 million increase in income attributable to non-controlling interests. Partially offsetting the unfavorable changes were the previously described improvement in year-to-date Adjusted EBITDA and a $46 million decrease in interest expense. The cash distribution coverage for the first six-month reporting period was 1.27x.

Williams Partners recently announced a regular quarterly cash distribution of $0.60 per unit, payable Aug. 11, 2017, to its common unitholders of record at the close of business on Aug. 4, 2017.

CEO Perspective

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

“The second quarter demonstrated once again the long-term, sustainable benefits of our focused strategy as we recognized year-over-year growth in Adjusted EBITDA for the 15^th consecutive quarter. We met or exceeded business performance expectations in all three remaining business units, offset by weaker than expected performance at Geismar, which was impacted by a continuing outage and lower margins. Strong performance in the Atlantic-Gulf, coupled with expected growth for the balance of the year, gives us confidence in achieving our prior guidance on Adjusted EBITDA and DCF.

We continue to deliver on project execution as planned for 2017. So far this year, we have successfully brought into service three Transco expansion projects including the 1.2 Bcf/d Gulf Trace project, the 0.8 Bcf/d Hillabee Phase 1 project, and just this week, the 0.4 Bcf/d Dalton Expansion project. The line of sight to future growth is evident as well as we are targeting second-half 2017 in-service dates for three more fully-contracted growth projects including Virginia Southside II, New York Bay, and Garden State Phase 1.

 

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“In addition to strong year-over-year fee-based revenue growth in the Atlantic-Gulf, we also saw gathered volumes in the West up approximately 4 percent versus first-quarter 2017, adjusted for the Marcellus-for-Permian transaction. While pipeline takeaway constraints continue to impact volumes in the Northeast, we remain well-positioned for volume growth as those constraints are lifted. We’re also pleased our Susquehanna and Ohio River Systems delivered year-over-year fee-based revenue growth. As we look ahead, around 97 percent of our gross margins will come from predictable fee-based sources now that we have successfully completed the sale of Geismar – reducing our commodity exposure and further strengthening our natural gas-focused strategy.

“We continue to see benefits from the reorganization of our operating areas and operational support functions such as safety and procurement. Continuous improvement in safety performance and project execution is another commitment that we are delivering on at the mid-point of 2017 and will continue to focus on as we move through the second half of the year.”

Business Segment Results

Effective, Jan. 1, 2017, Williams Partners implemented certain changes in its reporting segments as part of an operational realignment. As a result beginning with the reporting of first-quarter 2017 financial results, Williams Partners operations are comprised of the following reportable segments: Atlantic-Gulf, West, Northeast G&P, and NGL & Petchem Services.

 

Williams Partners		Modified and Adjusted EBITDA
Amounts in millions		2Q 2017												2Q 2016												YTD 2017												YTD 2016
		Modified EBITDA				Adjust.				Adjusted EBITDA				Modified EBITDA				Adjust.				Adjusted EBITDA				Modified EBITDA				Adjust.				Adjusted EBITDA				Modified EBITDA				Adjust.				Adjusted EBITDA
Atlantic-Gulf		$	454			$	8			$	462			$	360			$	8			$	368			$	904			$	11			$	915			$	742			$	31			$	773
West			356				16				372				312				112				424				741				20				761				639				185				824
Northeast G&P			247				1				248				222				—				222				473				2				475				442				5				447
NGL & Petchem Services			30				(7	)			23				(290	)			341				51				81				(9	)			72				(264	)			345				81
Other			(11	)			10				(1	)			—				—				—				9				(11	)			(2	)			—				—				—
Total		$	1,076			$	28			$	1,104			$	604			$	461			$	1,065			$	2,208			$	13			$	2,221			$	1,559			$	566			$	2,125

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

Atlantic-Gulf

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

The Atlantic-Gulf segment reported Modified EBITDA of $454 million for second-quarter 2017, compared with $360 million for second-quarter 2016. Adjusted EBITDA increased by $94 million to $462 million for the same reporting period. The increase in both measures was driven primarily by $88 million increased fee-based revenues due primarily to higher volumes from Gulfstar One and Transco expansion projects placed in service, as well as higher proportional EBITDA from joint ventures related to an $11 million increase from Discovery. Partially offsetting the favorable results were $14 million in increased O&M expenses due primarily to higher costs associated with Transco’s integrity and pipeline maintenance program.

Year-to-date, the Atlantic-Gulf segment reported Modified EBITDA of $904 million, an increase of $162 million over the same six-month period in 2016. Adjusted EBITDA increased $142 million to $915 million. The drivers for the increase in both measures are an improvement in fee-based revenues due primarily to higher volumes from Gulfstar One and Transco expansion projects placed in service, $18 million higher proportional EBITDA from joint ventures primarily from Discovery, and $13 million higher commodity margins. Partially offsetting these improvements were increased O&M expenses due primarily to higher costs associated with Transco’s integrity and pipeline maintenance program and the segment’s offshore business.

 

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West

This segment includes the partnership’s interstate natural gas pipeline, Northwest Pipeline, and natural gas gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian basins. This reporting segment also includes an NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL. The partnership completed the sale of its 50 percent equity-method investment in a Delaware Basin gas gathering system in the Mid-Continent region during first-quarter 2017.

The West segment reported Modified EBITDA of $356 million for second-quarter 2017, compared with $312 million for second-quarter 2016. Adjusted EBITDA decreased by $52 million to $372 million. The increase in Modified EBITDA was driven primarily by the absence of $48 million of impairments that impacted second-quarter 2016, which are excluded from Adjusted EBITDA. The decrease in Adjusted EBITDA was due primarily to $51 million lower fee-based revenues; including $18 million lower fee-based revenues in the Barnett from lower volumes and contract changes that occurred during 2016. Revenues in the Niobrara decreased by $7 million due to a change in revenue recognition timing resulting from contract restructuring. The unfavorable change in Adjusted EBITDA was also impacted by $10 million in decreased proportional EBITDA of joint ventures, due in part to the partnership’s sale of its interests in certain non-operated Delaware Basin assets in first-quarter 2017. Volume decreases in other areas also contributed to the unfavorable change. Partially offsetting the decrease was a $14 million decline in O&M and SG&A expenses.

Year-to-date, the West segment reported Modified EBITDA of $741 million, an increase of $102 million over the same six-month period in 2016. Adjusted EBITDA decreased by $63 million to $761 million. The increase in Modified EBITDA was driven primarily by a $65 million improvement in other income and expense, which included the absence of the impairments that impacted second-quarter 2016 and are excluded from Adjusted EBITDA. The favorable change also reflects $46 million in reduced O&M and SG&A expenses, $8 million of which are excluded from the Adjusted EBITDA measure. The decrease in Adjusted EBITDA was driven primarily by $108 million lower fee-based revenues; including $44 million lower fee-based revenues in the Barnett from lower volumes and contract changes that occurred during 2016. Revenues in the Niobrara decreased by $17 million due to a change in revenue recognition timing resulting from contract restructuring. The unfavorable change in Adjusted EBITDA was also impacted by $10 million in decreased proportional EBITDA of joint ventures, due in part to the partnership’s sale of its interests in certain non-operated Delaware Basin assets in first-quarter 2017. Volume decreases in other areas also contributed to the unfavorable change. Partially offsetting the decreases were the reduced O&M and SG&A expenses described above and $17 million in improved commodity margins.

Northeast G&P

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

The Northeast G&P segment reported Modified EBITDA of $247 million for second-quarter 2017, compared with $222 million for second-quarter 2016. Adjusted EBITDA increased by $26 million to $248 million. The improvement in both measures was driven primarily by a $22 million increase in proportional EBITDA of joint ventures due largely to the partnership’s increase in ownership in two Marcellus shale gathering systems in first-quarter 2017. Fee-based revenues were stable between the two periods due to increases in the Susquehanna and Ohio River systems that offset decreases in the Utica.

Year-to-date, the Northeast G&P segment reported Modified EBITDA of $473 million, an increase of $31 million over the same six-month period in 2016. Adjusted EBITDA increased by $28 million to $475 million. The improvement in both measures was driven primarily by a $21 million increase in proportional EBITDA of joint ventures due largely to the partnership’s increase in ownership in two Marcellus shale gathering systems in first-quarter 2017. Fee-based revenues were stable between the two periods due to increases in the Susquehanna and Ohio River systems that offset decreases in the Utica.

 

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NGL & Petchem Services

On Jan. 1, 2017 this segment included the partnership’s 88.46 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter. On July 6, 2017, the partnership announced that it had completed the sale of all of its membership interest in the Geismar olefins production facility and associated complex. On June 30, 2017 the partnership completed the sale of the refinery grade propylene splitter. Prior to September 2016, this reporting segment also included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility, which were subsequently sold.

The NGL & Petchem Services segment reported Modified EBITDA of $30 million for second-quarter 2017, compared with ($290) million for second-quarter 2016. Adjusted EBITDA decreased by $28 million to $23 million. The favorable change in Modified EBITDA was driven primarily by the absence of a second-quarter 2016, $341 million impairment charge associated with Williams Partners’ now former Canadian business that was sold in September 2016. Adjusted EBITDA was unfavorably impacted by a $22 million decrease in olefins margins due primarily to lower volumes at the Geismar olefins plant due to an unexpected power outage at the plant that resulted in the facility being offline from March 12 until restarting on April 18, 2017. Lower volumes at the RGP Splitter in connection with its sale on June 30 also contributed to the unfavorable change. The quarter’s unfavorable change in Adjusted EBITDA also reflects a $19 million decrease in fee-based revenues due primarily to the third-quarter 2016 sale of the partnership’s now former Canadian business. Partially offsetting these decreases was a $15 million reduction in O&M and SG&A expenses due primarily to the September 2016 sale of the partnership’s now former Canadian business.

Year-to-date, the NGL & Petchem Services segment reported Modified EBITDA of $81 million, an improvement of $345 million over the same six-month period in 2016. Adjusted EBITDA decreased $9 million to $72 million. The favorable change in Modified EBITDA was driven primarily by the absence of a second-quarter 2016, $341 million impairment charge associated with Williams Partners’ now former Canadian business that was sold in September 2016. Adjusted EBITDA was unfavorably impacted by a $24 million decrease in fee-based revenues and a $22 million decrease in olefins margins due primarily to lower volumes. The Geismar olefins plant had lower volumes due to the previously described power outage. The segment’s lower fee-based revenues and olefins margins also reflect the sale of the partnership’s now former Canadian business in September 2016. Partially offsetting these decreases was a $28 million reduction in O&M and SG&A expenses due primarily to the third-quarter 2016 sale of Williams Partners’ now former Canadian business.

Williams Partners does not expect significant future operating results from this segment; however, as a result of the sale of its interest in the Geismar olefins facility referenced above, the partnership expects to record a gain of approximately $1.1 billion in the third quarter of 2017.

Atlantic Sunrise Update

Williams Partners received notice to proceed on the mainline portion of the project, and construction activities are underway. In third-quarter 2017, the partnership expects to begin early mainline service and to receive final permits on the greenfield portion of the project. Williams Partners continues to target mid-2018 for the project’s full in-service date.

Guidance

The Guidance previously provided at our Analyst Day event on May 11, 2017, remains unchanged.

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

Williams Partners’ second-quarter 2017 financial results package will be posted shortly at www.williams.com. The materials will include the analyst package.

Williams Partners and Williams will host a joint Q&A live webcast on Thursday, Aug. 3 at 9:30 a.m. Eastern Daylight Time (8:30 a.m. Central Daylight Time). A limited number of phone lines will be available at (877) 419-6594. International callers should dial (719) 325-4888. The conference ID is 9171330. The link to the webcast, as well as replays of the webcast, will be available for at least 90 days following the event at www.williams.com.

Form 10-Q

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

 

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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:

 

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Levels of cash distributions with respect to limited partner interests;

 

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Our and our affiliates’ future credit ratings;

 

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Amounts and nature of future capital expenditures;

 

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Expansion and growth of our business and operations;

 

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Expected in-service dates for capital projects;

 

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Financial condition and liquidity;

 

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Business strategy;

 

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Cash flow from operations or results of operations;

 

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Seasonality of certain business components;

 

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

 

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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:

 

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

 

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Whether we elect to pay expected levels of cash distributions;

 

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

 

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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;

 

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

 

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

 

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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);

 

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

 

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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;

 

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Our ability to successfully expand our facilities and operations;

 

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Development and rate of adoption of alternative energy sources;

 

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

 

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

 

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

 

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Changes in maintenance and construction costs;

 

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Changes in the current geopolitical situation;

 

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

 

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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;

 

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

 

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

 

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

 

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

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

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

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

 

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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.

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Williams Partners L.P.

Reconciliation of Non-GAAP Measures

(UNAUDITED)

 

		2016																				2017
(Dollars in millions, except coverage ratios)		1st Qtr				2nd Qtr				3rd Qtr				4th Qtr				Year				1st Qtr				2nd Qtr				Year
Williams Partners L.P.
Reconciliation of GAAP “Net Income (Loss)” to Non-GAAP “Modified EBITDA”, “Adjusted EBITDA”, and “Distributable cash flow”
Net income (loss)		$	79			$	(77	)		$	351			$	166			$	519			$	660			$	348			$	1,008
Provision (benefit) for income taxes			1				(80	)			(6	)			5				(80	)			3				1				4
Interest expense			229				231				229				227				916				214				205				419
Equity (earnings) losses			(97	)			(101	)			(104	)			(95	)			(397	)			(107	)			(125	)			(232	)
Impairment of equity-method investments			112				—				—				318				430				—				—				—
Other investing (income) loss			—				(1	)			(28	)			—				(29	)			(271	)			(2	)			(273	)
Proportional Modified EBITDA of equity-method investments			189				191				194				180				754				194				215				409
Depreciation and amortization expenses			435				432				426				427				1,720				433				423				856
Accretion for asset retirement obligations associated with nonregulated operations			7				9				8				7				31				6				11				17
Modified EBITDA			955				604				1,070				1,235				3,864				1,132				1,076				2,208
Adjustments
Estimated minimum volume commitments			60				64				70				(194	)			—				15				15				30
Severance and related costs			25				—				—				12				37				9				4				13
Potential rate refunds associated with rate case litigation			15				—				—				—				15				—				—				—
Merger and transition related expenses			5				—				—				—				5				—				4				4
Constitution Pipeline project development costs			—				8				11				9				28				2				6				8
Share of impairment at equity-method investment			—				—				6				19				25				—				—				—
Geismar Incident adjustment for insurance and timing			—				—				—				(7	)			(7	)			(9	)			2				(7	)
Impairment of certain assets			—				389				—				22				411				—				—				—
Organizational realignment-related costs			—				—				—				24				24				4				6				10
Loss related to Canada disposition			—				—				32				2				34				(3	)			(1	)			(4	)
Gain on asset retirement			—				—				—				(11	)			(11	)			—				—				—
Gains from contract settlements and terminations			—				—				—				—				—				(13	)			(2	)			(15	)
Accrual for loss contingency			—				—				—				—				—				9				—				9
Gain on early retirement of debt			—				—				—				—				—				(30	)			—				(30	)
Gain on sale of RGP Splitter			—				—				—				—				—				—				(12	)			(12	)
Expenses associated with Financial Repositioning			—				—				—				—				—				—				2				2
Expenses associated with strategic asset monetizations			—				—				—				2				2				1				4				5
Total EBITDA adjustments			105				461				119				(122	)			563				(15	)			28				13
Adjusted EBITDA			1,060				1,065				1,189				1,113				4,427				1,117				1,104				2,221
Maintenance capital expenditures (1)			(58	)			(75	)			(121	)			(147	)			(401	)			(53	)			(100	)			(153	)
Interest expense (cash portion) (2)			(241	)			(245	)			(244	)			(239	)			(969	)			(224	)			(216	)			(440	)
Cash taxes			—				—				—				(3	)			(3	)			(5	)			(1	)			(6	)
Income attributable to noncontrolling interests (3)			(29	)			(13	)			(31	)			(27	)			(100	)			(27	)			(32	)			(59	)
WPZ restricted stock unit non-cash compensation			7				5				2				2				16				2				1				3
Amortization of deferred revenue associated with certain 2016 contract restructurings			—				—				—				—				—				(58	)			(58	)			(116	)
Distributable cash flow attributable to Partnership Operations (4)			739				737				795				699				2,970				752				698				1,450
Total cash distributed (5)		$	725			$	725			$	734			$	762			$	2,946			$	567			$	574			$	1,141
Coverage ratios:
Distributable cash flow attributable to partnership operations divided by Total cash distributed			1.02				1.02				1.08				0.92				1.01				1.33				1.22				1.27
Net income (loss) divided by Total cash distributed			0.11				(0.11	)			0.48				0.22				0.18				1.16				0.61				0.88

 

(1)	Includes proportionate share of maintenance capital expenditures of equity investments.

(2)	Includes proportionate share of interest expense of equity investments.

(3)	Excludes allocable share of certain EBITDA adjustments.

(4)	The fourth quarter of 2016 includes income of $183 million associated with proceeds from the contract restructuring in the Barnett Shale and Mid-Continent region as the cash was received during 2016.

(5)

In order to exclude the impact of the IDR waiver associated with the WPZ merger termination fee from the determination of coverage ratios, cash distributions have been increased by $10 million in the first quarter of 2016. Cash distributions for the third quarter of 2016 have been increased to exclude the impact of the $150 million IDR waiver associated with the sale of our Canadian operations. Cash distributions for the fourth quarter of 2016 and the first quarter of 2017 have been decreased by $50 million and $6 million, respectively, to reflect the amount paid by WMB to WPZ pursuant to the January 2017 Common Unit Purchase Agreement.

 

 

9

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Williams Partners L.P.

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

(UNAUDITED)

 

		2016																				2017
(Dollars in millions)		1st Qtr				2nd Qtr				3rd Qtr				4th Qtr				Year				1st Qtr				2nd Qtr				Year
Modified EBITDA:
Northeast G&P		$	220			$	222			$	214			$	197			$	853			$	226			$	247			$	473
Atlantic-Gulf			382				360				423				456				1,621				450				454				904
West			327				312				363				542				1,544				385				356				741
NGL & Petchem Services			26				(290	)			70				49				(145	)			51				30				81
Other			—				—				—				(9	)			(9	)			20				(11	)			9
Total Modified EBITDA		$	955			$	604			$	1,070			$	1,235			$	3,864			$	1,132			$	1,076			$	2,208
Adjustments:
Northeast G&P
Severance and related costs		$	3			$	—			$	—			$	—			$	3			$	—			$	—			$	—
Share of impairment at equity-method investments			—				—				6				19				25				—				—				—
ACMP Merger and transition costs			2				—				—				—				2				—				—				—
Organizational realignment-related costs			—				—				—				3				3				1				1				2
Total Northeast G&P adjustments			5				—				6				22				33				1				1				2
Atlantic-Gulf
Potential rate refunds associated with rate case litigation			15				—				—				—				15				—				—				—
Severance and related costs			8				—				—				—				8				—				—				—
Constitution Pipeline project development costs			—				8				11				9				28				2				6				8
Organizational realignment-related costs			—				—				—				—				—				1				2				3
Gain on asset retirement			—				—				—				(11	)			(11	)			—				—				—
Total Atlantic-Gulf adjustments			23				8				11				(2	)			40				3				8				11
West
Estimated minimum volume commitments			60				64				70				(194	)			—				15				15				30
Severance and related costs			10				—				—				3				13				—				—				—
ACMP Merger and transition costs			3				—				—				—				3				—				—				—
Impairment of certain assets			—				48				—				22				70				—				—				—
Organizational realignment-related costs			—				—				—				21				21				2				3				5
Gains from contract settlements and terminations			—				—				—				—				—				(13	)			(2	)			(15	)
Total West adjustments			73				112				70				(148	)			107				4				16				20
NGL & Petchem Services
Impairment of certain assets			—				341				—				—				341				—				—				—
Loss related to Canada disposition			—				—				32				2				34				(3	)			(1	)			(4	)
Severance and related costs			4				—				—				—				4				—				—				—
Expenses associated with strategic asset monetizations			—				—				—				2				2				1				4				5
Geismar Incident adjustment for insurance and timing			—				—				—				(7	)			(7	)			(9	)			2				(7	)
Gain on sale of RGP Splitter			—				—				—				—				—				—				(12	)			(12	)
Accrual for loss contingency			—				—				—				—				—				9				—				9
Total NGL & Petchem Services adjustments			4				341				32				(3	)			374				(2	)			(7	)			(9	)
Other
Severance and related costs			—				—				—				9				9				9				4				13
ACMP Merger-related expenses			—				—				—				—				—				—				4				4
Expenses associated with Financial Repositioning			—				—				—				—				—				—				2				2
Gain on early retirement of debt			—				—				—				—				—				(30	)			—				(30	)
Total Other adjustments			—				—				—				9				9				(21	)			10				(11	)
Total Adjustments		$	105			$	461			$	119			$	(122	)		$	563			$	(15	)		$	28			$	13
Adjusted EBITDA:
Northeast G&P		$	225			$	222			$	220			$	219			$	886			$	227			$	248			$	475
Atlantic-Gulf			405				368				434				454				1,661				453				462				915
West			400				424				433				394				1,651				389				372				761
NGL & Petchem Services			30				51				102				46				229				49				23				72
Other			—				—				—				—				—				(1	)			(1	)			(2	)
Total Adjusted EBITDA		$	1,060			$	1,065			$	1,189			$	1,113			$	4,427			$	1,117			$	1,104			$	2,221

 

10

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Financial Highlights and Operating Statistics

(UNAUDITED)

Final

June 30, 2017

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Williams Partners L.P.

Reconciliation of Non-GAAP Measures

(UNAUDITED)

 

		2016																				2017
(Dollars in millions, except coverage ratios)		1st Qtr				2nd Qtr				3rd Qtr				4th Qtr				Year				1st Qtr				2nd Qtr				Year
Williams Partners L.P.
Reconciliation of GAAP “Net Income (Loss)” to Non-GAAP “Modified EBITDA”, “Adjusted EBITDA”, and “Distributable cash flow”
Net income (loss)		$	79			$	(77	)		$	351			$	166			$	519			$	660			$	348			$	1,008
Provision (benefit) for income taxes			1				(80	)			(6	)			5				(80	)			3				1				4
Interest expense			229				231				229				227				916				214				205				419
Equity (earnings) losses			(97	)			(101	)			(104	)			(95	)			(397	)			(107	)			(125	)			(232	)
Impairment of equity-method investments			112				—				—				318				430				—				—				—
Other investing (income) loss			—				(1	)			(28	)			—				(29	)			(271	)			(2	)			(273	)
Proportional Modified EBITDA of equity-method investments			189				191				194				180				754				194				215				409
Depreciation and amortization expenses			435				432				426				427				1,720				433				423				856
Accretion for asset retirement obligations associated with nonregulated operations			7				9				8				7				31				6				11				17
Modified EBITDA			955				604				1,070				1,235				3,864				1,132				1,076				2,208
Adjustments
Estimated minimum volume commitments			60				64				70				(194	)			—				15				15				30
Severance and related costs			25				—				—				12				37				9				4				13
Potential rate refunds associated with rate case litigation			15				—				—				—				15				—				—				—
ACMP Merger and transition costs			5				—				—				—				5				—				4				4
Constitution Pipeline project development costs			—				8				11				9				28				2				6				8
Share of impairment at equity-method investment			—				—				6				19				25				—				—				—
Geismar Incident adjustment for insurance and timing			—				—				—				(7	)			(7	)			(9	)			2				(7	)
Impairment of certain assets			—				389				—				22				411				—				—				—
Organizational realignment-related costs			—				—				—				24				24				4				6				10
Loss related to Canada disposition			—				—				32				2				34				(3	)			(1	)			(4	)
Gain on asset retirement			—				—				—				(11	)			(11	)			—				—				—
Gains from contract settlements and terminations			—				—				—				—				—				(13	)			(2	)			(15	)
Accrual for loss contingency			—				—				—				—				—				9				—				9
Gain on early retirement of debt			—				—				—				—				—				(30	)			—				(30	)
Gain on sale of RGP Splitter			—				—				—				—				—				—				(12	)			(12	)
Expenses associated with Financial Repositioning			—				—				—				—				—				—				2				2
Expenses associated with strategic asset monetizations			—				—				—				2				2				1				4				5
Total EBITDA adjustments			105				461				119				(122	)			563				(15	)			28				13
Adjusted EBITDA			1,060				1,065				1,189				1,113				4,427				1,117				1,104				2,221
Maintenance capital expenditures (1)			(58	)			(75	)			(121	)			(147	)			(401	)			(53	)			(100	)			(153	)
Interest expense (cash portion) (2)			(241	)			(245	)			(244	)			(239	)			(969	)			(224	)			(216	)			(440	)
Cash taxes			—				—				—				(3	)			(3	)			(5	)			(1	)			(6	)
Income attributable to noncontrolling interests (3)			(29	)			(13	)			(31	)			(27	)			(100	)			(27	)			(32	)			(59	)
WPZ restricted stock unit non-cash compensation			7				5				2				2				16				2				1				3
Amortization of deferred revenue associated with certain 2016 contract restructurings			—				—				—				—				—				(58	)			(58	)			(116	)
Distributable cash flow attributable to Partnership Operations (4)			739				737				795				699				2,970				752				698				1,450
Total cash distributed (5)		$	725			$	725			$	734			$	762			$	2,946			$	567			$	574			$	1,141
Coverage ratios:
Distributable cash flow attributable to partnership operations divided by Total cash distributed			1.02				1.02				1.08				0.92				1.01				1.33				1.22				1.27
Net income (loss) divided by Total cash distributed			0.11				(0.11	)			0.48				0.22				0.18				1.16				0.61				0.88

 

(1)	Includes proportionate share of maintenance capital expenditures of equity investments.

(2)	Includes proportionate share of interest expense of equity investments.

(3)	Excludes allocable share of certain EBITDA adjustments.

(4)	The fourth quarter of 2016 includes income of $183 million associated with proceeds from the contract restructuring in the Barnett Shale and Mid-Continent region as the cash was received during 2016.

(5)

In order to exclude the impact of the IDR waiver associated with the WPZ merger termination fee from the determination of coverage ratios, cash distributions have been increased by $10 million in the first quarter of 2016. Cash distributions for the third quarter of 2016 have been increased to exclude the impact of the $150 million IDR waiver associated with the sale of our Canadian operations. Cash distributions for the fourth quarter of 2016 and the first quarter of 2017 have been decreased by $50 million and $6 million, respectively, to reflect the amount paid by WMB to WPZ pursuant to the January 2017 Common Unit Purchase Agreement.

---

Williams Partners L.P.

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

(UNAUDITED)

 

		2016																				2017
(Dollars in millions)		1st Qtr				2nd Qtr				3rd Qtr				4th Qtr				Year				1st Qtr				2nd Qtr				Year
Modified EBITDA:
Northeast G&P		$	220			$	222			$	214			$	197			$	853			$	226			$	247			$	473
Atlantic-Gulf			382				360				423				456				1,621				450				454				904
West			327				312				363				542				1,544				385				356				741
NGL & Petchem Services			26				(290	)			70				49				(145	)			51				30				81
Other			—				—				—				(9	)			(9	)			20				(11	)			9
Total Modified EBITDA		$	955			$	604			$	1,070			$	1,235			$	3,864			$	1,132			$	1,076			$	2,208
Adjustments:
Northeast G&P
Severance and related costs		$	3			$	—			$	—			$	—			$	3			$	—			$	—			$	—
Share of impairment at equity-method investments			—				—				6				19				25				—				—				—
ACMP Merger and transition costs			2				—				—				—				2				—				—				—
Organizational realignment-related costs			—				—				—				3				3				1				1				2
Total Northeast G&P adjustments			5				—				6				22				33				1				1				2
Atlantic-Gulf
Potential rate refunds associated with rate case litigation			15				—				—				—				15				—				—				—
Severance and related costs			8				—				—				—				8				—				—				—
Constitution Pipeline project development costs			—				8				11				9				28				2				6				8
Organizational realignment-related costs			—				—				—				—				—				1				2				3
Gain on asset retirement			—				—				—				(11	)			(11	)			—				—				—
Total Atlantic-Gulf adjustments			23				8				11				(2	)			40				3				8				11
West
Estimated minimum volume commitments			60				64				70				(194	)			—				15				15				30
Severance and related costs			10				—				—				3				13				—				—				—
ACMP Merger and transition costs			3				—				—				—				3				—				—				—
Impairment of certain assets			—				48				—				22				70				—				—				—
Organizational realignment-related costs			—				—				—				21				21				2				3				5
Gains from contract settlements and terminations			—				—				—				—				—				(13	)			(2	)			(15	)
Total West adjustments			73				112				70				(148	)			107				4				16				20
NGL & Petchem Services
Impairment of certain assets			—				341				—				—				341				—				—				—
Loss related to Canada disposition			—				—				32				2				34				(3	)			(1	)			(4	)
Severance and related costs			4				—				—				—				4				—				—				—
Expenses associated with strategic asset monetizations			—				—				—				2				2				1				4				5
Geismar Incident adjustment for insurance and timing			—				—				—				(7	)			(7	)			(9	)			2				(7	)
Gain on sale of RGP Splitter			—				—				—				—				—				—				(12	)			(12	)
Accrual for loss contingency			—				—				—				—				—				9				—				9
Total NGL & Petchem Services adjustments			4				341				32				(3	)			374				(2	)			(7	)			(9	)
Other
Severance and related costs			—				—				—				9				9				9				4				13
ACMP Merger and transition costs			—				—				—				—				—				—				4				4
Expenses associated with Financial Repositioning			—				—				—				—				—				—				2				2
Gain on early retirement of debt			—				—				—				—				—				(30	)			—				(30	)
Total Other adjustments			—				—				—				9				9				(21	)			10				(11	)
Total Adjustments		$	105			$	461			$	119			$	(122	)		$	563			$	(15	)		$	28			$	13
Adjusted EBITDA:
Northeast G&P		$	225			$	222			$	220			$	219			$	886			$	227			$	248			$	475
Atlantic-Gulf			405				368				434				454				1,661				453				462				915
West			400				424				433				394				1,651				389				372				761
NGL & Petchem Services			30				51				102				46				229				49				23				72
Other			—				—				—				—				—				(1	)			(1	)			(2	)
Total Adjusted EBITDA		$	1,060			$	1,065			$	1,189			$	1,113			$	4,427			$	1,117			$	1,104			$	2,221

---

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				Year
Revenues:
Service revenues		$	1,226			$	1,210			$	1,252			$	1,485			$	5,173			$	1,256			$	1,277			$	2,533
Product sales			428				530				655				705				2,318				727				642				1,369
Total revenues			1,654				1,740				1,907				2,190				7,491				1,983				1,919				3,902
Costs and expenses:
Product costs			317				403				463				545				1,728				579				537				1,116
Operating and maintenance expenses			382				386				385				395				1,548				361				384				745
Depreciation and amortization expenses			435				432				426				427				1,720				433				423				856
Selling, general, and administrative expenses			181				139				147				163				630				156				154				310
Net insurance recoveries - Geismar Incident			—				—				—				(7	)			(7	)			(9	)			2				(7	)
Impairment of certain assets			6				396				1				54				457				1				2				3
Other (income) expense - net			24				24				59				11				118				12				5				17
Total costs and expenses			1,345				1,780				1,481				1,588				6,194				1,533				1,507				3,040
Operating income (loss)			309				(40	)			426				602				1,297				450				412				862
Equity earnings (losses)			97				101				104				95				397				107				125				232
Impairment of equity-method investments			(112	)			—				—				(318	)			(430	)			—				—				—
Other investing income (loss) - net			—				1				28				—				29				271				2				273
Interest incurred			(240	)			(239	)			(236	)			(234	)			(949	)			(221	)			(214	)			(435	)
Interest capitalized			11				8				7				7				33				7				9				16
Other income (expense) - net			15				12				16				19				62				49				15				64
Income (loss) before income taxes			80				(157	)			345				171				439				663				349				1,012
Provision (benefit) for income taxes			1				(80	)			(6	)			5				(80	)			3				1				4
Net income (loss)			79				(77	)			351				166				519				660				348				1,008
Less: Net income attributable to noncontrolling interests			29				13				25				21				88				26				28				54
Net income (loss) attributable to controlling interests		$	50			$	(90	)		$	326			$	145			$	431			$	634			$	320			$	954
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			$	954
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				17
Allocation of net income (loss) to common units (1)		$	(148	)		$	(289	)		$	247			$	143			$	(98	)		$	623			$	314			$	937
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			$	1.00
Weighted average number of common units outstanding (thousands)			588,562				588,607				591,567				601,738				592,519				920,250				955,986				938,217
Cash distributions per common unit		$	0.85			$	0.85			$	0.85			$	0.85			$	3.40			$	0.60			$	0.60			$	1.20

 

(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				Year
Revenues:
Service revenues:
Nonregulated gathering and processing fee-based revenue		$	186			$	182			$	179			$	184			$	731			$	182			$	183			$	365
Other fee revenues			37				40				39				42				158				40				38				78
Product sales:
NGL sales from gas processing			4				3				3				4				14				4				4				8
Marketing sales			19				31				40				58				148				64				48				112
			246				256				261				288				1,051				290				273				563
Intrasegment eliminations			(4	)			(6	)			(4	)			(5	)			(19	)			(5	)			(4	)			(9	)
Total revenues			242				250				257				283				1,032				285				269				554
Segment costs and expenses:
NGL cost of goods sold			1				2				1				2				6				4				1				5
Marketing cost of goods sold			20				32				41				60				153				65				48				113
Other segment costs and expenses (1)			99				91				95				98				383				91				93				184
Impairment of certain assets			4				4				—				5				13				1				1				2
Intrasegment eliminations			(4	)			(6	)			(4	)			(5	)			(19	)			(5	)			(4	)			(9	)
Total segment costs and expenses			120				123				133				160				536				156				139				295
Proportional Modified EBITDA of equity-method investments			98				95				90				74				357				97				117				214
Modified EBITDA			220				222				214				197				853				226				247				473
Adjustments			5				—				6				22				33				1				1				2
Adjusted EBITDA		$	225			$	222			$	220			$	219			$	886			$	227			$	248			$	475
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				3.30
Gathering volumes (Bcf per day) - Non-consolidated (3)			3.21				3.16				3.08				3.20				3.16				3.55				3.58				3.57
Plant inlet natural gas volumes (Bcf per day) (2)			0.31				0.31				0.34				0.37				0.33				0.39				0.40				0.39
Ethane equity sales (Mbbls/d)			6				4				3				3				4				2				2				2
Non-ethane equity sales (Mbbls/d)			1				1				1				1				1				1				1				1
NGL equity sales (Mbbls/d)			7				5				4				4				5				3				3				3
Ethane production (Mbbls/d)			14				18				22				20				18				17				22				19
Non-ethane production (Mbbls/d)			11				12				16				15				14				15				17				16
NGL production (Mbbls/d)			25				30				38				35				32				32				39				35

 

(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				Year
Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue		$	92			$	76			$	131			$	137			$	436			$	127			$	136			$	263
Regulated transportation revenue			349				331				339				348				1,367				354				358				712
Other fee revenues			24				41				41				42				148				54				42				96
Product sales:
NGL sales from gas processing			8				11				24				31				74				27				16				43
Marketing sales			45				75				78				84				282				90				75				165
Other sales			—				—				4				4				8				1				—				1
Tracked revenues			38				39				51				39				167				36				52				88
			556				573				668				685				2,482				689				679				1,368
Intrasegment eliminations			(9	)			(10	)			(9	)			(6	)			(34	)			(19	)			(7	)			(26	)
Total revenues			547				563				659				679				2,448				670				672				1,342
Segment costs and expenses:
NGL cost of goods sold			3				4				15				15				37				13				7				20
Marketing cost of goods sold			45				74				78				83				280				88				75				163
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				345
Tracked costs			38				39				51				39				167				36				52				88
Intrasegment eliminations			(9	)			(10	)			(9	)			(6	)			(34	)			(19	)			(7	)			(26	)
Total segment costs and expenses			231				271				311				301				1,114				292				298				590
Proportional Modified EBITDA of equity-method investments			66				68				75				78				287				72				80				152
Modifed EBITDA			382				360				423				456				1,621				450				454				904
Adjustments			23				8				11				—				42				3				8				11
Adjusted EBITDA		$	405			$	368			$	434			$	456			$	1,663			$	453			$	462			$	915
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
Gathering volumes (Bcf per day) - Non-consolidated (3)			0.53				0.54				0.60				0.60				0.56				0.55				0.54				0.54
Plant inlet natural gas volumes (Bcf per day) - Consolidated (2)			0.64				0.60				0.84				0.78				0.72				0.56				0.57				0.56
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				0.54
Crude transportation volumes (Mbbls/d)			98				99				126				128				113				131				135				133
Consolidated (2)
Ethane margin ($/gallon)		$	.03			$	.05			$	(.03	)		$	(.01	)		$	—			$	.02			$	.03				0.02
Non-ethane margin ($/gallon)		$	.30			$	.38			$	.26			$	.35			$	.31			$	.42			$	.36				0.40
NGL margin ($/gallon)		$	.21			$	.18			$	.16			$	.20			$	.19			$	.26			$	.23				0.25
Ethane equity sales (Mbbls/d)			2				6				6				8				5				6				4				5
Non-ethane equity sales (Mbbls/d)			4				4				11				12				8				9				6				7
NGL equity sales (Mbbls/d)			6				10				17				20				13				15				10				12
Ethane production (Mbbls/d)			13				17				16				19				16				14				14				14
Non-ethane production (Mbbls/d)			20				20				31				30				25				20				19				20
NGL production (Mbbls/d)			33				37				47				49				41				34				33				34
Non-consolidated (3)
NGL equity sales (Mbbls/d)			5				5				5				5				5				5				4				5
NGL production (Mbbls/d)			17				19				21				21				20				21				22				22
Transcontinental Gas Pipe Line
Throughput (Tbtu)			927.2				815.9				878.1				881.5				3,502.7				939.1				887.6				1,826.7
Avg. daily transportation volumes (Tbtu)			10.2				9.0				9.5				9.6				9.6				10.4				9.8				10.1
Avg. daily firm reserved capacity (Tbtu)			12.0				11.5				11.6				11.9				11.7				12.8				13.2				13.0

 

(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				Year
Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue		$	376			$	379			$	374			$	593			$	1,722			$	364			$	382			$	746
Regulated transportation revenue			118				111				114				117				460				117				112				229
Other fee revenues			42				44				43				44				173				43				38				81
Product sales:
NGL sales from gas processing			38				54				53				58				203				64				61				125
Olefin sales			—				—				—				—				—				1				—				1
Marketing sales			269				342				396				504				1,511				506				490				996
Other sales			6				4				5				4				19				6				8				14
Tracked revenues			—				1				—				—				1				—				1				1
			849				935				985				1,320				4,089				1,101				1,092				2,193
Intrasegment eliminations			(76	)			(101	)			(95	)			(109	)			(381	)			(127	)			(130	)			(257	)
Total revenues			773				834				890				1,211				3,708				974				962				1,936
Segment costs and expenses:
NGL cost of goods sold			18				22				26				25				91				27				31				58
Marketing cost of goods sold			271				345				396				494				1,506				505				498				1,003
Other cost of goods sold			5				3				5				3				16				5				4				9
Other segment costs and expenses (1)			252				231				223				235				941				204				220				424
Impairment of certain assets			1				49				1				49				100				—				1				1
Tracked costs			—				1				—				—				1				—				—				—
Intrasegment eliminations			(76	)			(101	)			(95	)			(109	)			(381	)			(127	)			(130	)			(257	)
Total segment costs and expenses			471				550				556				697				2,274				614				624				1,238
Proportional Modified EBITDA of equity-method investments			25				28				29				28				110				25				18				43
Modifed EBITDA			327				312				363				542				1,544				385				356				741
Adjustments			73				112				70				(148	)			107				4				16				20
Adjusted EBITDA		$	400			$	424			$	433			$	394			$	1,651			$	389			$	372			$	761
Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day)			4.60				4.68				4.72				4.50				4.63				4.23				4.40				4.32
Plant inlet natural gas volumes (Bcf per day)			2.51				2.51				2.48				2.32				2.45				1.99				2.00				1.99
Ethane equity sales (Mbbls/d)			4				15				6				4				7				3				11				7
Non-ethane equity sales (Mbbls/d)			20				22				23				21				21				20				20				20
NGL equity sales (Mbbls/d)			24				37				29				25				28				23				31				27
Ethane margin ($/gallon)		$	.03			$	.00			$	.00			$	.00			$	.01			$	.04			$	.00			$	.01
Non-ethane margin ($/gallon)		$	.26			$	.39			$	.31			$	.41			$	.34			$	.49			$	.40			$	.45
NGL margin ($/gallon)		$	.22			$	.23			$	.24			$	.34			$	.26			$	.43			$	.26			$	.34
Ethane production (Mbbls/d)			12				25				10				9				14				8				18				13
Non-ethane production (Mbbls/d)			64				66				65				62				64				55				57				56
NGL production (Mbbls/d)			76				91				75				71				78				63				75				69
Northwest Pipeline LLC
Throughput (Tbtu)			205.6				168.0				161.9				191.6				727.1				219.0				165.4				384.4
Avg. daily transportation volumes (Tbtu)			2.3				1.8				1.8				2.1				2.0				2.4				1.8				2.1
Avg. daily firm reserved capacity (Tbtu)			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				38,896

 

(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				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				305
Marketing sales			28				27				45				39				139				56				38				94
Other sales			—				—				2				—				2				—				—				—
			189				204				279				202				874				219				187				406
Intrasegment eliminations			(13	)			(8	)			(21	)			(5	)			(47	)			(17	)			(26	)			(43	)
Total revenues			176				196				258				197				827				202				161				363
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				182
Marketing cost of goods sold			28				29				41				40				138				52				40				92
Other cost of goods sold			1				—				2				—				3				—				—				—
Net insurance recoveries - Geismar Incident			—				—				—				(7	)			(7	)			(9	)			2				(7	)
Impairment of certain assets			—				341				—				1				342				—				—				—
Other segment costs and expenses (1)			57				45				72				33				207				36				22				58
Intrasegment eliminations			(13	)			(8	)			(21	)			(5	)			(47	)			(17	)			(26	)			(43	)
Total segment costs and expenses			150				486				188				148				972				151				131				282
Modified EBITDA			26				(290	)			70				49				(145	)			51				30				81
Adjustments			4				341				32				(3	)			374				(2	)			(7	)			(9	)
Adjusted EBITDA		$	30			$	51			$	102			$	46			$	229			$	49			$	23			$	72
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 (Mbble/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				Year
Capital expenditures:
Northeast G&P		$	67			$	55			$	46			$	56			$	224			$	58			$	81			$	139
Atlantic-Gulf			300				410				380				345				1,435				388				398				786
West			62				33				63				70				228				57				58				115
NGL & Petchem Services			34				18				4				1				57				6				1				7
Other			—				2				(2	)			—				—				—				2				2
Total (1)		$	463			$	518			$	491			$	472			$	1,944			$	509			$	540			$	1,049
Purchases of investments:
Northeast G&P		$	24			$	40			$	(16	)		$	24			$	72			$	20			$	26			$	46
Atlantic-Gulf			—				—				—				—				—				—				1				1
West			39				19				26				21				105				32				—				32
Total		$	63			$	59			$	10			$	45			$	177			$	52			$	27			$	79
Summary:
Northeast G&P		$	91			$	95			$	30			$	80			$	296			$	78			$	107			$	185
Atlantic-Gulf			300				410				380				345				1,435				388				399				787
West			101				52				89				91				333				89				58				147
NGL & Petchem Services			34				18				4				1				57				6				1				7
Other			—				2				(2	)			—				—				—				2				2
Total		$	526			$	577			$	501			$	517			$	2,121			$	561			$	567			$	1,128
Capital expenditures incurred and purchases of investments:
Increases to property, plant, and equipment		$	498			$	485			$	446			$	442			$	1,871			$	569			$	586			$	1,155
Purchases of investments			63				59				10				45				177				52				27				79
Total		$	561			$	544			$	456			$	487			$	2,048			$	621			$	613			$	1,234
(1) Increases to property, plant, and equipment		$	498			$	485			$	446			$	442			$	1,871			$	569			$	586			$	1,155
Changes in related accounts payable and accrued liabilities			(35	)			33				45				30				73				(60	)			(46	)			(106	)
Capital expenditures		$	463			$	518			$	491			$	472			$	1,944			$	509			$	540			$	1,049

---

Selected Financial Information

(UNAUDITED)

 

		2016																2017
(Dollars in millions)		1st Qtr				2nd Qtr				3rd Qtr				4th Qtr				1st Qtr				2nd Qtr
Cash and cash equivalents		$	125			$	101			$	68			$	145			$	625			$	1,908
Capital structure:
Debt:
Commercial paper		$	135			$	196			$	2			$	93			$	—			$	—
Current		$	976			$	786			$	785			$	785			$	—			$	1,951
Noncurrent		$	18,504			$	19,116			$	18,918			$	17,685			$	17,065			$	16,614