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

 

 

DATE: Oct. 31, 2016

 

MEDIA CONTACT:		INVESTOR CONTACTS:
Keith Isbell (918) 573-7308		John Porter (918) 573-0797		Brett Krieg (918) 573-4614

Williams Partners Reports Strong Third-Quarter 2016 Financial Results

 

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Continued Solid Financial Performance; Increasing Fee-Based Revenue; Cost Reductions

 

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3Q 2016 Cash Flow from Operations of $676 million, Up $71 million or 12%

 

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3Q 2016 Net Income of $326 million, Up $520 million

 

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3Q 2016 Adjusted EBITDA of $1.189 billion, Up $89 million or 8%

 

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Coverage Ratio of 1.08x Driven by Distributable Cash Flow of $795 million, Up $41 million or 5%

 

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Revised 2017 Capital Expenditure Guidance Related Primarily to Atlantic Sunrise Project Timing

TULSA, Okla. – Williams Partners L.P. (NYSE: WPZ) today announced its financial results for the three and nine months ended Sept. 30, 2016.

 

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.			2016				2015				2016				2015
GAAP Measures
Cash Flow from Operations		$	676			$	605			$	2,341			$	2,098
Net income (loss)		$	326			($	194	)		$	286			$	195
Net income (loss) per common unit		$	0.42			($	0.32	)		($	0.32	)		($	0.50	)
Non-GAAP Measures (1)
Adjusted EBITDA		$	1,189			$	1,100			$	3,314			$	3,025
DCF attributable to partnership operations		$	795			$	754			$	2,271			$	2,101
Cash distribution coverage ratio			1.08x				1.04x				1.04x				0.97x

 

(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.

 

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Third-Quarter 2016 Financial Results

Williams Partners reported third-quarter 2016 unaudited net income of $326 million, compared to a $194 million net loss from third-quarter 2015. The favorable change was driven by the absence of $461 million of impairments of equity-method investments recognized in 2015. The improvement also reflected higher olefins margins at our Geismar plant, lower operating and maintenance (O&M) and selling, general and administrative (SG&A) expenses, and higher service revenues associated with expansion projects, partially offset by a $32 million additional loss associated with the completion of the sale of our Canadian operations and expensed project development costs.

Year-to-date, Williams Partners reported unaudited net income of $286 million, a $91 million increase over the same time period in 2015. The favorable change was driven by lower impairments of equity-method investments, higher service revenues, an increase in olefins margins associated with our Geismar plant, decreases in O&M and SG&A expenses, and higher equity earnings. These favorable changes were partially offset by increased property-impairment charges and the additional loss on sale associated with our Canadian operations, the absence of $126 million of insurance recoveries, and higher interest incurred.

Williams Partners reported third-quarter 2016 Adjusted EBITDA of $1.189 billion, an $89 million increase over third-quarter 2015. The increase is due primarily to $37 million higher fee-based revenues, $33 million higher olefins margins and $21 million lower O&M and SG&A expenses.

Year-to-date, Williams Partners reported Adjusted EBITDA of $3.314 billion, an increase of $289 million over the same nine-month reporting period in 2015. The increase is due primarily to $108 million of higher olefins margins, $99 million of higher fee-based revenues, $83 million of lower O&M and SG&A expenses and $50 million of higher proportional EBITDA from joint ventures. Partially offsetting these increases was a $19 million unfavorable change in foreign currency exchange gains and losses related to our former Canadian operations divested in September 2016.

Distributable Cash Flow and Distributions

For third-quarter 2016, Williams Partners generated $795 million in distributable cash flow (DCF) attributable to partnership operations, compared with $754 million in DCF attributable to partnership operations for the same period last year. The $41 million increase in DCF for the quarter was driven by an $89 million increase in Adjusted EBITDA, partially offset by $25 million higher interest expense. For third-quarter 2016, the cash distribution coverage was 1.08x.

Year-to-date, Williams Partners generated $2.271 billion in DCF, an increase of $170 million over the same period in 2015. The increase was due to a $289 million increase in Adjusted EBITDA partially offset by $100 million higher interest expense. Year-to-date, the cash distribution coverage was 1.04x.

Williams Partners recently announced a regular quarterly cash distribution of $0.85 per unit for its common unitholders payable on Nov. 14, 2016 to unitholders of record at the close of business on Nov. 4, 2016.

In August 2016, Williams reinvested $250 million via a private placement to purchase WPZ common units pursuant to its previously announced plans.

CEO Perspective

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

“With Adjusted EBITDA growth across all five of the partnership’s operating areas and increased distributable cash flow achieved by Williams Partners, our strong third-quarter results highlighted once again the effectiveness of our strategy and how well-positioned we are to capture natural gas demand growth now and in the future.

“Our recent accomplishments reflect disciplined execution against our business plan. The new Kodiak, Gunflint and Rock Springs facilities all contributed to our growth in the third quarter. Despite the expanding number of major projects recently placed in-service, we reduced expenses on a year-to-date basis. We also completed win-win contract renegotiations with our customer Chesapeake and completed the sale of our Canadian businesses as we continue to take decisive actions to position our company for predictable growth.

 

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“Our future growth is also visible in the number of projects now under construction. After receiving the necessary permits to begin construction, we began work in the third quarter on Dalton, Virginia Southside II and Phase 1 of Hillabee. Construction on our New York Bay Expansion project began this month while construction also continues on our Gulf Trace project. We are aiming to place all of these Transco-expansion projects into service next year.”

Business Segment Results

 

Williams Partners		Modified and Adjusted EBITDA
Amounts in millions		3Q 2016				3Q 2016								3Q 2015				3Q 2015								YTD 2016												YTD 2015
		Modified EBITDA				Adjust.				Adjusted EBITDA				Modified EBITDA				Adjust.				Adjusted EBITDA				Modified EBITDA				Adjust.				Adjusted EBITDA				Modified EBITDA				Adjust.				Adjusted EBITDA
Atlantic-Gulf		$	416			$	11			$	427			$	414			$	—			$	414			$	1,149			$	42			$	1,191			$	1,138			$	—			$	1,138
Central			176				70				246				163				67				230				467				251				718				456				224				680
NGL & Petchem Services			104				32				136				85				—				85				(104	)			377				273				249				(124	)			125
Northeast G&P			208				6				214				189				19				208				638				11				649				557				52				609
West			166				—				166				169				(8	)			161				479				4				483				480				(7	)			473
Other			—				—				—				1				1				2				—				—				—				11				(11	)			—
Total		$	1,070			$	119			$	1,189			$	1,021			$	79			$	1,100			$	2,629			$	685			$	3,314			$	2,891			$	134			$	3,025

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

Atlantic-Gulf

Atlantic-Gulf operating area includes the Transco interstate gas pipeline and 41 percent interest in Constitution interstate gas pipeline development project, which Williams Partners consolidates. The segment also includes the partnership’s significant natural gas gathering and processing and crude oil production and handling and transportation in the Gulf Coast region. These operations include a 51 percent consolidated interest in Gulfstar One, a 50 percent equity method interest in Gulfstream and a 60 percent equity-method interest in the Discovery pipeline and processing system.

Atlantic-Gulf reported Modified EBITDA of $416 million for third-quarter 2016, compared with $414 million for third-quarter 2015. Adjusted EBITDA increased by $13 million to $427 million for the same time period. The increase in Modified EBITDA is due primarily to $31 million higher fee-based revenues from both offshore gathering and processing operations (including the new Gunflint and Kodiak facilities) as well as Transco’s new expansion projects. Substantially offsetting the higher fee-based revenues were $20 million in higher O&M expenses primarily related to pipeline safety testing activities as well as expensed project development costs.

Year-to-date, Atlantic-Gulf reported Modified EBITDA of $1.149 billion, an increase of $11 million over the same time period in 2015. Adjusted EBITDA increased $53 million to $1.191 billion. The increase in Modified EBITDA was due primarily to $27 million higher fee-based revenues from both Transco’s new expansion projects as well as offshore gathering and processing operations (including the new Gunflint and Kodiak facilities) and $25 million higher proportional EBITDA from Discovery due to increased contributions from Keathley Canyon Connector. Modified EBITDA was also unfavorably impacted by potential rate refunds associated with litigation, severance-related costs, and project development costs, all of which are excluded from Adjusted EBITDA.

Central

The Central operating area includes operations that were previously part of the former Access Midstream segment located in Louisiana, Texas, Arkansas and Oklahoma. These operations became the Central operating area effective Jan. 1, 2016 and prior-period segment disclosures have been recast for this change. Central provides gathering, treating and compression services to producers under long-term, fee-based contracts. The segment also includes a non-operated 50 percent interest in the Delaware Basin gas gathering system in the Mid-Continent region.

 

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The Central operating area reported Modified EBITDA of $176 million for third-quarter 2016, an increase of $13 million from third-quarter 2015. Adjusted EBITDA increased by $16 million to $246 million. The increase is due primarily to $20 million lower O&M and SG&A expenses partially offset by lower fee-based revenues.

Year-to-date, the Central operating area reported Modified EBITDA of $467 million, an increase of $11 million from the same nine-month reporting period in 2015. Adjusted EBITDA increased $38 million to $718 million. The increase in Modified EBITDA was due primarily to $63 million of lower O&M and SG&A expenses due to cost reduction efforts and the absence of certain merger and transition costs in the prior year partially offset by lower fee-based revenues and a $48 million impairment charge in the second quarter of 2016 related to a gathering system. Adjusted EBITDA excludes the impairment charge and benefits from the absence of prior-year merger and transition costs, as well as estimated minimum volume commitments.

NGL & Petchem Services

NGL & Petchem Services operating area includes an 88.5 percent undivided ownership interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter and pipelines in the Gulf Coast region. This segment also includes the partnership’s energy commodities marketing business, an NGL fractionator and storage facilities near Conway, Kan. and a 50 percent equity-method interest in Overland Pass Pipeline. Prior to the sale of all of our Canadian-based assets effective Sept. 23, 2016, this segment included midstream operations in Alberta, Canada, including an oil sands offgas processing plant near Fort McMurray, 261 miles of NGL and olefins pipelines and an NGL/olefins fractionation facility at Redwater.

NGL & Petchem Services operating area reported Modified EBITDA of $104 million for third-quarter 2016, compared with $85 million for third-quarter 2015. Adjusted EBITDA increased by $51 million to $136 million. The $19 million increase in Modified EBITDA was due primarily to $33 million higher olefins margins and $8 million higher fee-based revenues. Geismar olefins margins for third-quarter 2016 reflected enhanced operational production levels and improved ethylene prices. Partially offsetting these increases was a $32 million additional loss associated with the completion of the sale of Canadian operations, which is excluded from Adjusted EBITDA.

Year-to-date, NGL & Petchem Services operating area reported Modified EBITDA of ($104) million compared with $249 million during the same time period in 2015. Adjusted EBITDA increased $148 million to $273 million. The decrease in Modified EBITDA was due primarily to a second quarter 2016 non-cash impairment charge of $341 million associated with our former Canadian operations, the additional loss associated with the sale, and the absence of $126 million business interruption proceeds. Partially offsetting these unfavorable items were $108 million favorable olefins margins at Geismar and $38 million favorable fee-based revenues due primarily to new fees associated with Williams’ Canadian offgas processing plant that came online in first quarter 2016. Adjusted EBITDA excludes the impairment charge, additional loss on sale and insurance proceeds.

Northeast G&P

Northeast G&P operating area includes the Susquehanna Supply Hub, Ohio Valley Midstream, Marcellus South, Bradford and Utica midstream gathering and processing operations as well as its 69-percent equity investment in Laurel Mountain Midstream, and its 58.4 percent equity investment in Caiman Energy II. Caiman Energy II owns a 50 percent interest in Blue Racer Midstream. The Marcellus South, Bradford and Utica midstream gathering and processing operations that were previously within the former Access Midstream segment became part of Northeast G&P effective Jan. 1, 2016 and prior period segment disclosures have been recast for this change.

Northeast G&P operating area reported Modified EBITDA of $208 million for third-quarter 2016, compared with $189 million for third-quarter 2015. Adjusted EBITDA increased $6 million to $214 million. The $19 million increase in Modified EBITDA was due primarily to $14 million of higher fee-based revenues.

Year-to-date, Northeast G&P operating area reported Modified EBITDA of $638 million, an increase of $81 million over the same period in 2015. Adjusted EBITDA increased $40 million to $649 million. The increase in Modified EBITDA is due primarily to higher fee-based revenues, lower O&M expenses, increased proportional Modified EBITDA of equity-method investments and the absence of certain 2015 impairment charges. Adjusted EBITDA excludes the prior year impairment charges.

 

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West

West operating area includes the partnership’s Northwest Pipeline interstate gas pipeline system, as well as gathering, processing and treating operations in Wyoming, the Piceance Basin and the Four Corners area.

West operating area reported Modified EBITDA of $166 million for third-quarter 2016, compared with $169 million for third-quarter 2015. Adjusted EBITDA of $166 million is $5 million higher than the same period in 2015. The $3 million decrease in Modified EBITDA was due primarily to the absence of an $8 million insurance settlement recorded in 2015 and lower fee-based revenues, substantially offset by $7 million lower O&M and SG&A expenses. Adjusted EBITDA excludes the effect of the 2015 insurance settlement.

Year-to-date, the West operating area reported Modified EBITDA of $479 million compared with $480 million over the same period in 2015. Adjusted EBITDA of $483 million is $10 million higher than the same period in 2015 due primarily to lower O&M and SG&A expenses.

Revised 2017 Growth Capital Guidance Related Primarily to Atlantic Sunrise Project Timing

Williams Partners is revising its 2017 growth capital guidance amounts due primarily to the shift in Transco and related Northeast G&P growth spending caused by the revised Atlantic Sunrise in-service date, as well as new projects and other changes. As discussed in its press release dated Oct. 28, 2016, Williams Partners expects partial Atlantic Sunrise service to begin during the second half of 2017 and is now targeting full in-service during mid-2018. Consistent with prior financial practice, Williams Partners’ financial plan further risks these project cash flows by approximately six months. The following guidance range represents both the targeted in-service date and the further risked in-service date: total 2017 growth capital and investment expenditures are expected to be between $2.1 billion and $2.8 billion, including total 2017 growth capital for Transco, which is expected to be between $1.4 billion and $1.9 billion.

Third-Quarter 2016 Materials to be Posted Shortly; Q&A Webcast Scheduled for This Morning

Williams Partners’ third-quarter 2016 financial results package will be posted shortly at www.williams.com. The package will include the data book and analyst package.

Williams and Williams Partners plan to jointly host a Q&A live webcast today, Oct. 31, at 9:30 a.m. EDT. A limited number of phone lines will be available at (888) 364-3105. International callers should dial (719) 8325-2228. The conference ID is 6961753. A link to the webcast, as well as replays of the webcast, will be available for two weeks following the event at www.williams.com.

Form 10-Q

The company plans to file its third-quarter 2016 Form 10-Q with the Securities and Exchange Commission this week. Once filed, the document will be available on both the SEC and Williams websites.

Definitions of Non-GAAP Measures

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

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

 

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Adjusted EBITDA further excludes items of income or loss that we characterize as unrepresentative of our ongoing operations and may include assumed business interruption insurance related to the Geismar plant. Management believes these measures provide investors meaningful insight into results from ongoing operations.

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

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

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

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

About Williams Partners

Williams Partners (NYSE: WPZ) is an industry-leading, large-cap natural gas infrastructure master limited partnership with a strong growth outlook and major positions in key U.S. supply basins. Williams Partners has operations across the natural gas value chain from gathering, processing and interstate transportation of natural gas and natural gas liquids to petchem production of ethylene, propylene and other olefins. Williams Partners owns and operates more than 33,000 miles of pipelines system wide – including the nation’s largest volume and fastest growing pipeline – providing natural gas for clean-power generation, heating and industrial use. Williams Partners’ operations touch approximately 30 percent of U.S. natural gas. Tulsa, Okla.-based Williams (NYSE: WMB), a premier provider of large-scale U.S. natural gas infrastructure, owns 60 percent of Williams Partners, including all of the 2 percent general-partner interest. www.williams.com

Forward-Looking Statements

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

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

Expected levels of cash distributions with respect to general partner interests, incentive distribution rights and limited partner interests;

Our and our affiliates’ future credit ratings;

 

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Amounts and nature of future capital expenditures;

Expansion of our business and operations;

Financial condition and liquidity;

Business strategy;

Cash flow from operations or results of operations;

Seasonality of certain business components;

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

Demand for our services.

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

Whether we have sufficient cash from operations to enable us to pay current and expected levels of cash distributions, if any, following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner;

Whether we will be able to effectively execute our financing plan including the receipt of anticipated levels of proceeds from planned asset sales;

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

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

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

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

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

Our ability to successfully expand our facilities and operations;

Development of alternative energy sources;

Availability of adequate insurance coverage and the impact of operational and developmental hazards and unforeseen interruptions;

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

Williams’ costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;

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

Changes in maintenance and construction costs;

Changes in the current geopolitical situation;

 

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

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

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

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

Acts of terrorism, including cybersecurity threats and related disruptions;

Additional risks described in our filings with the SEC.

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

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

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

Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on Feb. 26, 2016 and in Part II, Item 1A. Risk Factors in our Quarterly Reports on Form 10-Q available from our office or from our website at www.williams.com

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Williams Partners L.P.

Reconciliation of Non-GAAP Measures

(UNAUDITED)

 

		2015																				2016
(Dollars in millions, except coverage ratios)		Ist Qtr				2nd Qtr				3rd Qtr				4th Qtr				Year				Ist Qtr				2nd Qtr				3rd Qtr				Year
Williams Partners L.P.
Reconciliation of GAAP “Net Income (Loss)” to Non-GAAP “Modified EBITDA”, “Adjusted EBITDA”, and “Distributable cash flow”
Neţ income (loss)		$	112			$	332			$	(167	)		$	(1,635	)		$	(1,358	)		$	79			$	(77	)		$	351			$	353
Provision (benefit) for income taxes			3				—				1				(3	)			1				1				(80	)			(6	)			(85	)
Interest expense			192				203				205				211				811				229				231				229				689
Equity (earnings) losses			(51	)			(93	)			(92	)			(99	)			(335	)			(97	)			(101	)			(104	)			(302	)
Impairment of equity-method investments			—				—				461				898				1,359				112				—				—				112
Other investing (income) loss			(1	)			—				—				(1	)			(2	)			—				(1	)			(28	)			(29	)
Proporţional Modified EBITDA of equity-method investments			136				183				185				195				699				189				191				194				574
Impairment of goodwill			—				—				—				1,098				1,098				—				—				—				—
Depreciation and amortization expenses			419				419				423				441				1,702				435				432				426				1,293
Accretion for asset retirement obligations associated with nonregulated operations			7				9				5				7				28				7				9				8				24
Modified EBITDA			817				1,053				1,021				1,112				4,003				955				604				1,070				2,629
Adjustments
Estimated minimum volume commitments			55				55				65				(175	)			—				60				64				70				194
Severance and related costs			—				—				—				—				—				25				—				—				25
Potential rate refunds associated with rate case litigation			—				—				—				—				—				15				—				—				15
Merger and transition related expenses			32				14				2				2				50				5				—				—				5
Constitution Pipeline project development costs			—				—				—				—				—				—				8				11				19
Share of impairment at equity-method investment			8				1				17				7				33				—				—				6				6
Geismar Incident adjustment for insurance and timing			—				(126	)			—				—				(126	)			—				—				—				—
Loss related to Geismar Incident			1				1				—				—				2				—				—				—				—
Impairment of certain assets			3				24				2				116				145				—				389				—				389
Loss related to Canada disposition			—				—				—				—				—				—				—				32				32
Loss (recovery) related to Opal incident			1				—				(8	)			1				(6	)			—				—				—				—
Gain on extinguishment of debt			—				(14	)			—				—				(14	)			—				—				—				—
Expenses associated with strategic alternatives			—				—				1				1				2				—				—				—				—
Total EBITDA adjustments			100				(45	)			79				(48	)			86				105				461				119				685
Adjusted EBITDA			917				1,008				1,100				1,064				4,089				1,060				1,065				1,189				3,314
Maintenance capital expenditures(1)			(54	)			(80	)			(114	)			(114	)			(362	)			(58	)			(75	)			(121	)			(254	)
Interest expense (cash portion)(2)			(204	)			(207	)			(219	)			(214	)			(844	)			(241	)			(245	)			(244	)			(730	)
Cash taxes			(1	)			—				—				—				(1	)			—				—				—				—
Income attributable to noncontrolling interests(3)			(23	)			(32	)			(27	)			(29	)			(111	)			(29	)			(13	)			(31	)			(73	)
WPZ restricted stock unit non-cash compensation			7				6				7				7				27				7				5				2				14
Plymouth incident adjustment			4				6				7				4				21				—				—				—				—
Distributable cash flow attributable to Partnership Operations			646				701				754				718				2,819				739				737				795				2,271
Total cash distributed (4)		$	725			$	723			$	723			$	725			$	2,896			$	725			$	725			$	734			$	2,184
Coverage ratios:
Distributable cash flow attributable to partnership operations divided by Total cash distributed			0.89				0.97				1.04				0.99				0.97				1.02				1.02				1.08				1.04
Net income (loss) divided by Total cash distributed			0.15				0.46				(0.23	)			(2.26	)			(0.47	)			0.11				(0.11	)			0.48				0.16

Notes:

 

(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 impairment of goodwill and certain EBITDA adjustments.

 

(4)

In order to exclude the impact of the IDR waiver Associated with the WPZ merger termination fee from the determination of coverage ratios, cash distributions have been increased for the 2015 third quarter, fourth quarter, and year by $209 million, $209 million, and $418 million, respectively, and by $10 million in the first quarter of 2016. 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.

 

9

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Williams Partners L.P.

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

(UNAUDITED)

 

		2015																				2016
(Dollars in millions)		Ist Qtr				2nd Qtr				3rd Qtr				4th Qtr				Year				Ist Qtr				2nd Qtr				3rd Qtr				Year
Modified EBITDA:
Central		$	133			$	160			$	163			$	384			$	840			$	157			$	134			$	176			$	467
Northeast G&P			185				183				189				196				753				214				216				208				638
Atlantic-Gulf			335				389				414				385				1,523				376				357				416				1,149
West			161				150				169				77				557				155				158				166				479
NGL & Petchem Services			6				158				85				72				321				53				(261	)			104				(104	)
Other			(3	)			13				1				(2	)			9				—				—				—				—
Total Modified EBITDA		$	817			$	1,053			$	1,021			$	1,112			$	4,003			$	955			$	604			$	1,070			$	2,629
Adjustments:
Central
Estimated minimum volume commitments		$	55			$	55			$	65			$	(175	)		$	—			$	60			$	64			$	70			$	194
Severance and related costs			—				—				—				—				—				6				—				—				6
ACMP Merger and transition costs			30				14				2				2				48				3				—				—				3
Impairment of certain assets			—				3				—				8				11				—				48				—				48
Total Central adjustments			85				72				67				(165	)			59				69				112				70				251
Northeast G&P
Severance and related costs			—				—				—				—				—				3				—				—				3
Share of impairment at equity-method investments			8				1				17				7				33				—				—				6				6
ACMP Merger and transition costs			—				—				—				—				—				2				—				—				2
Impairment of certain assets			3				21				2				6				32				—				—				—				—
Total Northeast G&P adjustments			11				22				19				13				65				5				—				6				11
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				19
Impairment of certain assets			—				—				—				5				5				—				—				—				—
Total Atlantic-Gulf adjustments			—				—				—				5				5				23				8				11				42
West
Severance and related costs			—				—				—				—				—				4				—				—				4
Impairment of certain assets			—				—				—				97				97				—				—				—				—
Loss (recovery) related to Opal incident			1				—				(8	)			1				(6	)			—				—				—				—
Total West adjustments			1				—				(8	)			98				91				4				—				—				4
NGL & Petchem Services
Impairment of certain assets			—				—				—				—				—				—				341				—				341
Loss related to Canada disposition			—				—				—				—				—				—				—				32				32
Severance and related costs			—				—				—				—				—				4				—				—				4
Loss related to Geismar Incident			1				1				—				—				2				—				—				—				—
Geismar Incident adjustment for insurance and timing			—				(126	)			—				—				(126	)			—				—				—				—
Total NGL & Petchem Services adjustments			1				(125	)			—				—				(124	)			4				341				32				377
Other
ACMP Merger-related expenses			2				—				—				—				2				—				—				—				—
Expenses associated with strategic alternatives			—				—				1				1				2				—				—				—				—
Gain on extinguishment of debt			—				(14	)			—				—				(14	)			—				—				—				—
Total Other adjustments			2				(14	)			1				1				(10	)			—				—				—				—
Total Adjustments		$	100			$	(45	)		$	79			$	(48	)		$	86			$	105			$	461			$	119			$	685
Adjusted EBITDA:
Central		$	218			$	232			$	230			$	219			$	899			$	226			$	246			$	246			$	718
Northeast G&P			196				205				208				208				818				219				216				214				649
Atlantic-Gulf			335				389				414				390				1,528				399				365				427				1,191
West			162				150				161				175				648				159				158				166				483
NGL & Petchem Services			7				33				85				72				197				57				80				136				273
Other			(1	)			(1	)			2				(1	)			(1	)			—				—				—				—
Total Adjusted EBITDA		$	917			$	1,008			$	1,100			$	1,064			$	4,089			$	1,060			$	1,065			$	1,189			$	3,314

 

10

---

 

Financial Highlights and Operating Statistics

(UNAUDITED)

Final

September 30, 2016

---

Williams Partners L.P.

Reconciliation of Non-GAAP Measures

(UNAUDITED)

 

		2015																				2016
(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 GAAP “Net Income (Loss)” to Non-GAAP “Modified EBITDA”, “Adjusted EBITDA”, and “Distributable cash flow”
Net income (loss)		$	112			$	332			$	(167	)		$	(1,635	)		$	(1,358	)		$	79			$	(77	)		$	351			$	353
Provision (benefit) for income taxes			3				—				1				(3	)			1				1				(80	)			(6	)			(85	)
Interest expense			192				203				205				211				811				229				231				229				689
Equity (earnings) losses			(51	)			(93	)			(92	)			(99	)			(335	)			(97	)			(101	)			(104	)			(302	)
Impairment of equity-method investments			—				—				461				898				1,359				112				—				—				112
Other investing (income) loss			(1	)			—				—				(1	)			(2	)			—				(1	)			(28	)			(29	)
Proportional Modified EBITDA of equity-method investments			136				183				185				195				699				189				191				194				574
Impairment of goodwill			—				—				—				1,098				1,098				—				—				—				—
Depreciation and amortization expenses			419				419				423				441				1,702				435				432				426				1,293
Accretion for asset retirement obligations associated with nonregulated operations			7				9				5				7				28				7				9				8				24
Modified EBITDA			817				1,053				1,021				1,112				4,003				955				604				1,070				2,629
Adjustments
Estimated minimum volume commitments			55				55				65				(175	)			—				60				64				70				194
Severance and related costs			—				—				—				—				—				25				—				—				25
Potential rate refunds associated with rate case litigation			—				—				—				—				—				15				—				—				15
Merger and transition related expenses			32				14				2				2				50				5				—				—				5
Constitution Pipeline project development costs			—				—				—				—				—				—				8				11				19
Share of impairment at equity-method investment			8				1				17				7				33				—				—				6				6
Geismar Incident adjustment for insurance and timing			—				(126	)			—				—				(126	)			—				—				—				—
Loss related to Geismar Incident			1				1				—				—				2				—				—				—				—
Impairment of certain assets			3				24				2				116				145				—				389				—				389
Loss related to Canada disposition			—				—				—				—				—				—				—				32				32
Loss (recovery) related to Opal incident			1				—				(8	)			1				(6	)			—				—				—				—
Gain on extinguishment of debt			—				(14	)			—				—				(14	)			—				—				—				—
Expenses associated with strategic alternatives			—				—				1				1				2				—				—				—				—
Total EBITDA adjustments			100				(45	)			79				(48	)			86				105				461				119				685
Adjusted EBITDA			917				1,008				1,100				1,064				4,089				1,060				1,065				1,189				3,314
Maintenance capital expenditures (1)			(54	)			(80	)			(114	)			(114	)			(362	)			(58	)			(75	)			(121	)			(254	)
Interest expense (cash portion) (2)			(204	)			(207	)			(219	)			(214	)			(844	)			(241	)			(245	)			(244	)			(730	)
Cash taxes			(1	)			—				—				—				(1	)			—				—				—				—
Income attributable to noncontrolling interests (3)			(23	)			(32	)			(27	)			(29	)			(111	)			(29	)			(13	)			(31	)			(73	)
WPZ restricted stock unit non-cash compensation			7				6				7				7				27				7				5				2				14
Plymouth incident adjustment			4				6				7				4				21				—				—				—				—
Distributable cash flow attributable to Partnership Operations			646				701				754				718				2,819				739				737				795				2,271
Total cash distributed (4)		$	725			$	723			$	723			$	725			$	2,896			$	725			$	725			$	734			$	2,184
Coverage ratios:
Distributable cash flow attributable to partnership operations divided by Total cash distributed			0.89				0.97				1.04				0.99				0.97				1.02				1.02				1.08				1.04
Net income (loss) divided by Total cash distributed			0.15				0.46				(0.23	)			(2.26	)			(0.47	)			0.11				(0.11	)			0.48				0.16

Notes:

 

(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 impairment of goodwill and certain EBITDA adjustments.

 

(4)

In order to exclude the impact of the IDR waiver associated with the WPZ merger termination fee from the determination of coverage ratios, cash distributions have been increased for the 2015 third quarter, fourth quarter, and year by $209 million, $209 million, and $418 million, respectively, and by $10 million in the first quarter of 2016. 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.

---

Williams Partners L.P.

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

(UNAUDITED)

 

		2015																				2016
(Dollars in millions)		1st Qtr				2nd Qtr				3rd Qtr				4th Qtr				Year				1st Qtr				2nd Qtr				3rd Qtr				Year
Modified EBITDA:
Central		$	133			$	160			$	163			$	384			$	840			$	157			$	134			$	176			$	467
Northeast G&P			185				183				189				196				753				214				216				208				638
Atlantic-Gulf			335				389				414				385				1,523				376				357				416				1,149
West			161				150				169				77				557				155				158				166				479
NGL & Petchem Services			6				158				85				72				321				53				(261	)			104				(104	)
Other			(3	)			13				1				(2	)			9				—				—				—				—
Total Modified EBITDA		$	817			$	1,053			$	1,021			$	1,112			$	4,003			$	955			$	604			$	1,070			$	2,629
Adjustments:
Central
Estimated minimum volume commitments		$	55			$	55			$	65			$	(175	)		$	—			$	60			$	64			$	70			$	194
Severance and related costs			—				—				—				—				—				6				—				—				6
ACMP Merger and transition costs			30				14				2				2				48				3				—				—				3
Impairment of certain assets			—				3				—				8				11				—				48				—				48
Total Central adjustments			85				72				67				(165	)			59				69				112				70				251
Northeast G&P
Severance and related costs			—				—				—				—				—				3				—				—				3
Share of impairment at equity-method investments			8				1				17				7				33				—				—				6				6
ACMP Merger and transition costs			—				—				—				—				—				2				—				—				2
Impairment of certain assets			3				21				2				6				32				—				—				—				—
Total Northeast G&P adjustments			11				22				19				13				65				5				—				6				11
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				19
Impairment of certain assets			—				—				—				5				5				—				—				—				—
Total Atlantic-Gulf adjustments			—				—				—				5				5				23				8				11				42
West
Severance and related costs			—				—				—				—				—				4				—				—				4
Impairment of certain assets			—				—				—				97				97				—				—				—				—
Loss (recovery) related to Opal incident			1				—				(8	)			1				(6	)			—				—				—				—
Total West adjustments			1				—				(8	)			98				91				4				—				—				4
NGL & Petchem Services
Impairment of certain assets			—				—				—				—				—				—				341				—				341
Loss related to Canada disposition			—				—				—				—				—				—				—				32				32
Severance and related costs			—				—				—				—				—				4				—				—				4
Loss related to Geismar Incident			1				1				—				—				2				—				—				—				—
Geismar Incident adjustment for insurance and timing			—				(126	)			—				—				(126	)			—				—				—				—
Total NGL & Petchem Services adjustments			1				(125	)			—				—				(124	)			4				341				32				377
Other
ACMP Merger-related expenses			2				—				—				—				2				—				—				—				—
Expenses associated with strategic alternatives			—				—				1				1				2				—				—				—				—
Gain on extinguishment of debt			—				(14	)			—				—				(14	)			—				—				—				—
Total Other adjustments			2				(14	)			1				1				(10	)			—				—				—				—
Total Adjustments		$	100			$	(45	)		$	79			$	(48	)		$	86			$	105			$	461			$	119			$	685
Adjusted EBITDA:
Central		$	218			$	232			$	230			$	219			$	899			$	226			$	246			$	246			$	718
Northeast G&P			196				205				208				209				818				219				216				214				649
Atlantic-Gulf			335				389				414				390				1,528				399				365				427				1,191
West			162				150				161				175				648				159				158				166				483
NGL & Petchem Services			7				33				85				72				197				57				80				136				273
Other			(1	)			(1	)			2				(1	)			(1	)			—				—				—				—
Total Adjusted EBITDA		$	917			$	1,008			$	1,100			$	1,064			$	4,089			$	1,060			$	1,065			$	1,189			$	3,314

---

Williams Partners L.P.

Consolidated Statement of Income (Loss)

(UNAUDITED)

 

		2015																				2016
(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		$	1,192			$	1,231			$	1,232			$	1,480			$	5,135			$	1,226			$	1,210			$	1,252			$	3,688
Product sales			519				599				560				518				2,196				428				530				655				1,613
Total revenues			1,711				1,830				1,792				1,998				7,331				1,654				1,740				1,907				5,301
Costs and expenses:
Product costs			463				494				426				396				1,779				317				403				463				1,183
Operating and maintenance expenses			380				431				394				420				1,625				382				386				385				1,153
Depreciation and amortization expenses			419				419				423				441				1,702				435				432				426				1,293
Selling, general, and administrative expenses			193				164				156				171				684				181				139				147				467
Impairment of goodwill			—				—				—				1,098				1,098				—				—				—				—
Net insurance recoveries – Geismar Incident			—				(126	)			—				—				(126	)			—				—				—				—
Impairment of long-lived assets			3				24				2				116				145				6				396				1				403
Other (income) expense – net			14				14				5				8				41				24				24				59				107
Total costs and expenses			1,472				1,420				1,406				2,650				6,948				1,345				1,780				1,481				4,606
Operating income (loss)			239				410				386				(652	)			383				309				(40	)			426				695
Equity earnings (losses)			51				93				92				99				335				97				101				104				302
Impairment of equity-method investments			—				—				(461	)			(898	)			(1,359	)			(112	)			—				—				(112	)
Other investing income (loss) – net			1				—				—				1				2				—				1				28				29
Interest incurred			(209	)			(215	)			(216	)			(224	)			(864	)			(240	)			(239	)			(236	)			(715	)
Interest capitalized			17				12				11				13				53				11				8				7				26
Other income (expense) – net			16				32				22				23				93				15				12				16				43
Income (loss) before income taxes			115				332				(166	)			(1,638	)			(1,357	)			80				(157	)			345				268
Provision (benefit) for income taxes			3				—				1				(3	)			1				1				(80	)			(6	)			(85	)
Net income (loss)			112				332				(167	)			(1,635	)			(1,358	)			79				(77	)			351				353
Less: Net income attributable to noncontrolling interests			23				32				27				9				91				29				13				25				67
Net income (loss) attributable to controlling interests		$	89			$	300			$	(194	)		$	(1,644	)		$	(1,449	)		$	50			$	(90	)		$	326			$	286
Allocation of net income (loss) for calculation of earnings per common unit:
Net income (loss) attributable to controlling interests		$	89			$	300			$	(194	)		$	(1,644	)		$	(1,449	)		$	50			$	(90	)		$	326			$	286
Allocation of net income (loss) to general partner			195				216				1				(28	)			384				202				207				72				481
Allocation of net income (loss) to Class B units (1)			(2	)			1				(5	)			(39	)			(46	)			(4	)			(8	)			7				(6	)
Allocation of net income (loss) to Class D units			68				—				—				—				68				—				—				—				—
Allocation of net income (loss) to common units (1)		$	(172	)		$	83			$	(190	)		$	(1,577	)		$	(1,855	)		$	(148	)		$	(289	)		$	247			$	(189	)
Diluted earnings (loss) per common unit:
Net income (loss) per common unit (1)		$	(.34	)		$	.14			$	(0.32	)		$	(2.68	)		$	(3.27	)		$	(.25	)		$	(.49	)		$	.42			$	(.32	)
Weighted average number of common units outstanding (thousands)			507,001				587,088				586,722				587,581				567,275				588,562				588,607				591,567				589,498
Cash distributions per common unit		$	.85			$	.85			$	.85			$	.85			$	3.40			$	.85			$	.85			$	.85			$	2.55

 

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

---

Williams Partners L.P.

Central

(UNAUDITED)

		2015																				2016
(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		$	242			$	247			$	256			$	486				1,231			$	240			$	243			$	240			$	723
Other fee revenues			10				18				14				14				56				15				15				15			$	45
			252				265				270				500				1,287				255				258				255				768
Intrasegment eliminations			—				—				—				—				—				—				—				—				—
Total revenues			252				265				270				500				1,287				255				258				255				768
Segment costs and expenses:
Other segment costs and expenses (1)			127				112				116				117				472				108				88				91				287
Impairment of long-lived assets			—				3				—				8				11				(1	)			48				1				48
Intrasegment eliminations			—				—				—				—				—				—				—				—				—
Total segment costs and expenses			127				115				116				125				483				107				136				92				335
Proportional Modified EBITDA of equity-method investments			8				10				9				9				36				9				12				13				34
Modified EBITDA			133				160				163				384				840				157				134				176				467
Adjustments			85				72				67				(165	)			59				69				112				70				251
Adjusted EBITDA		$	218			$	232			$	230			$	219			$	899			$	226			$	246			$	246			$	718
Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day) – Consolidated (2)			2.60				2.71				2.63				2.44				2.59				2.43				2.50				2.55				2.49

 

(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.

---

Williams Partners L.P.

Northeast G&P

(UNAUDITED)

 

		2015																				2016
(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		$	185			$	183			$	170			$	183			$	721			$	186			$	182			$	180			$	548
Other fee revenues			11				33				25				20				89				26				29				29				84
Product sales:
NGL sales from gas processing			2				3				3				3				11				4				3				3				10
Marketing sales			36				32				23				25				116				20				30				40				90
			234				251				221				231				937				236				244				252				732
Intrasegment eliminations			—				—				—				—				—				(1	)			(3	)			(2	)			(6	)
Total revenues			234				251				221				231				937				235				241				250				726
Segment costs and expenses:
NGL cost of goods sold			1				1				—				2				4				1				2				1				4
Marketing cost of goods sold			36				32				25				24				117				20				32				41				93
Other segment costs and expenses (1)			85				108				86				101				380				94				86				90				270
Impairment of long-lived assets			3				21				2				6				32				4				4				—				8
Intrasegment eliminations			—				—				—				—				—				(1	)			(3	)			(1	)			(5	)
Total segment costs and expenses			125				162				113				133				533				118				121				131				370
Proportional Modified EBITDA of equity-method investments			76				94				81				98				349				97				96				89				282
Modified EBITDA			185				183				189				196				753				214				216				208				638
Adjustments			11				22				19				13				65				5				—				6				11
Adjusted EBITDA		$	196			$	205			$	208			$	209			$	818			$	219			$	216			$	214			$	649
Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day) – Consolidated (2)			3.30				3.06				2.87				3.19				3.10				3.34				3.15				3.16				3.22
Gathering volumes (Bcf per day) – Non-consolidated (3)			3.00				3.05				3.10				3.06				3.05				3.21				3.16				3.08				3.15
Plant inlet natural gas volumes (Bcf per day) (2)			0.31				0.38				0.38				0.28				0.34				0.31				0.31				0.34				0.32
Ethane equity sales (million gallons)			4				11				16				23				54				23				16				10				49
Non-ethane equity sales (million gallons)			2				3				4				4				13				5				6				4				15
NGL equity sales (million gallons)			6				14				20				27				67				28				22				14				64
Ethane production (million gallons)			4				43				52				50				149				55				69				84				208
Non-ethane production (million gallons)			45				56				61				41				203				41				46				61				148
NGL production (million gallons)			49				99				113				91				352				96				115				145				356

 

(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, 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)

 

		2015																				2016
(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		$	95			$	106			$	102			$	94			$	397			$	82			$	67			$	120			$	269
Regulated transportation revenue			308				312				328				337				1,285				349				331				339				1,019
Other fee revenues			29				29				29				32				119				14				32				31				77
Product sales:
NGL sales from gas processing			11				7				11				10				39				8				11				25				44
Marketing sales			87				80				63				64				294				45				75				78				198
Other sales			—				1				—				—				1				—				—				3				3
Tracked revenues			49				56				63				42				210				38				39				51				128
			579				591				596				579				2,345				536				555				647				1,738
Intrasegment eliminations			—				—				(1	)			—				(1	)			(1	)			(2	)			(2	)			(5	)
Total revenues			579				591				595				579				2,344				535				553				645				1,733
Segment costs and expenses:
NGL cost of goods sold			4				2				3				3				12				3				4				15				22
Marketing cost of goods sold			87				80				63				63				293				45				74				77				196
Other cost of goods sold			—				—				—				—				—				—				—				2				2
Impairment of long-lived assets			—				—				—				5				5				1				—				—				1
Other segment costs and expenses (1)			142				131				131				155				559				139				149				161				449
Tracked costs			49				56				63				42				210				38				39				51				128
Intrasegment eliminations			—				—				(1	)			—				(1	)			(1	)			(2	)			(2	)			(5	)
Total segment costs and expenses			282				269				259				268				1,078				225				264				304				793
Proportional Modified EBITDA of equity-method investments			38				67				78				74				257				66				68				75				209
Modified EBITDA			335				389				414				385				1,523				376				357				416				1,149
Adjustments			—				—				—				5				5				23				8				11				42
Adjusted EBITDA		$	335			$	389			$	414			$	390			$	1,528			$	399			$	365			$	427			$	1,191
Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day)—Consolidated (2)			0.32				0.36				0.35				0.31				0.34				0.30				0.30				0.52				0.37
Gathering volumes (Bcf per day)—Non-consolidated (3)			0.34				0.62				0.63				0.59				0.55				0.53				0.54				0.60				0.55
Plant inlet natural gas volumes (Bcf per day)—Consolidated (2)			0.69				0.60				0.67				0.68				0.66				0.64				0.60				0.84				0.69
Plant inlet natural gas volumes (Bcf per day)—Non-consolidated (3)			0.36				0.62				0.63				0.60				0.55				0.56				0.54				0.60				0.57
Consolidated (2)
Ethane margin ($/gallon)		$	.04			$	(.07	)		$	.04			$	.02			$	.03			$	.03			$	.05			$	(.03	)		$	.01
Non-ethane margin ($/gallon)		$	.43			$	.49			$	.42			$	.42			$	.43			$	.30			$	.38			$	.26			$	.29
NGL margin ($/gallon)		$	.26			$	.41			$	.32			$	.26			$	.30			$	.21			$	.18			$	.16			$	.18
Ethane equity sales (million gallons)			11				2				7				10				30				8				22				21				51
Non-ethane equity sales (million gallons)			15				12				17				16				60				16				15				41				72
NGL equity sales (million gallons)			26				14				24				26				90				24				37				62				123
Ethane production (million gallons)			38				33				36				46				153				48				66				61				175
Non-ethane production (million gallons)			94				87				93				86				360				76				76				120				272
NGL production (million gallons)			132				120				129				132				513				124				142				181				447
Non-consolidated (3)
NGL equity sales (million gallons)			17				22				21				20				80				20				19				20				59
NGL production (million gallons)			62				79				81				72				294				65				74				82				221
Transcontinental Gas Pipe Line
Throughput (Tbtu)			1,005.1				784.9				803.6				779.3				3,372.9				927.2				815.9				878.1				2,621.2
Avg. daily transportation volumes (Tbtu)			11.2				8.6				8.7				8.5				9.2				10.2				9.0				9.5				9.6
Avg. daily firm reserved capacity (Tbtu)			10.5				11.0				11.5				11.8				11.2				12.0				11.5				11.6				11.7

 

(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)

 

		2015																				2016
(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		$	138			$	138			$	138			$	147			$	561			$	136			$	137			$	134			$	407
Regulated transportation revenue			116				112				115				117				460				118				111				114				343
Other fee revenues			8				7				10				7				32				9				8				9				26
Product sales:
NGL sales from gas processing			48				49				43				47				187				38				54				53				145
Marketing sales			10				15				15				13				53				11				21				15				47
Other sales			6				4				4				3				17				3				3				2				8
Tracked revenues			—				1				—				1				2				—				1				—				1
			326				326				325				335				1,312				315				335				327				977
Intrasegment eliminations			—				—				—				—				—				—				(2	)			(1	)			(3	)
Total revenues			326				326				325				335				1,312				315				333				326				974
Segment costs and expenses:
NGL cost of goods sold			23				20				20				19				82				18				21				26				65
Marketing cost of goods sold			10				15				15				13				53				11				21				14				46
Other cost of goods sold			3				2				3				2				10				2				1				1				4
Other segment costs and expenses (1)			129				138				118				126				511				127				132				120				379
Impairment of long-lived assets			—				—				—				97				97				2				1				—				3
Tracked costs			—				1				—				1				2				—				1				—				1
Intrasegment eliminations			—				—				—				—				—				—				(2	)			(1	)			(3	)
Total segment costs and expenses			165				176				156				258				755				160				175				160				495
Proportional Modified EBITDA of equity-method investments			—				—				—				—				—				—				—				—				—
Modified EBITDA			161				150				169				77				557				155				158				166				479
Adjustments			1				—				(8	)			98				91				4				—				—				4
Adjusted EBITDA		$	162			$	150			$	161			$	175			$	648			$	159			$	158			$	166			$	483
Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day)			2.35				2.31				2.31				2.26				2.31				2.18				2.19				2.19				2.18
Plant inlet natural gas volumes (Bcf per day)			2.58				2.55				2.49				2.47				2.52				2.51				2.51				2.47				2.49
Ethane equity sales (million gallons)			2				4				4				2				12				16				59				23				98
Non-ethane equity sales (million gallons)			74				76				75				78				303				76				83				87				246
NGL equity sales (million gallons)			76				80				79				80				315				92				142				110				344
Ethane margin ($/gallon)		$	.39			$	.14			$	.28			$	.40			$	.27			$	.03			$	.00			$	.00			$	.01
Non-ethane margin ($/gallon)		$	.34			$	.37			$	.29			$	.35			$	.34			$	.26			$	.39			$	.31			$	.32
NGL margin ($/gallon)		$	.34			$	.35			$	.29			$	.35			$	.33			$	.22			$	.23			$	.24			$	.23
Ethane production (million gallons)			33				40				37				30				140				47				94				38				179
Non-ethane production (million gallons)			239				248				255				253				995				245				252				246				743
NGL production (million gallons)			272				288				292				283				1,135				292				346				284				922
Northwest Pipeline LLC
Throughput (Tbtu)			202.7				183.0				177.9				199.2				762.8				205.6				168.0				161.9				535.5
Avg. daily transportation volumes (Tbtu)			2.3				2.0				1.9				2.2				2.1				2.3				1.8				1.8				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

 

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

---

Williams Partners L.P.

NGL & Petchem Services

(UNAUDITED)

 

		2015																				2016
(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		$	7			$	10			$	11			$	11			$	39			$	11			$	12			$	12			$	35
Other fee-based revenues			41				42				47				46				176				47				60				54				161
Product sales:
NGL sales from gas processing			28				18				19				20				85				17				3				16				36
Olefin sales			71				162				174				148				555				136				151				202				489
Marketing sales			378				372				337				341				1,428				285				348				427				1,060
Other sales			4				4				1				4				13				2				3				4				9
			529				608				589				570				2,296				498				577				715				1,790
Intrasegment eliminations			(54	)			(61	)			(60	)			(61	)			(236	)			(54	)			(50	)			(82	)			(186	)
Total revenues			475				547				529				509				2,060				444				527				633				1,604
Segment costs and expenses:
NGL cost of goods sold			19				16				14				15				64				12				2				10				24
Olefins cost of goods sold			62				101				89				77				329				65				77				84				226
Marketing cost of goods sold			381				376				340				340				1,437				287				354				423				1,064
Other cost of goods sold			6				4				2				5				17				4				2				5				11
Net insurance recoveries – Geismar Incident			—				(126	)			—				—				(126	)			—				—				—				—
Impairment of long-lived assets			—				—				—				—				—				—				343				—				343
Other segment costs and expenses (1)			66				88				71				71				296				94				75				106				275
Intrasegment eliminations			(54	)			(61	)			(60	)			(61	)			(236	)			(54	)			(50	)			(82	)			(186	)
Total segment costs and expenses			480				398				456				447				1,781				408				803				546				1,757
Proportional Modified EBITDA of equity-method investments			11				9				12				10				42				17				15				17				49
Modified EBITDA			6				158				85				72				321				53				(261	)			104				(104	)
Adjustments			1				(125	)			—				—				(124	)			4				341				32				377
Adjusted EBITDA		$	7			$	33			$	85			$	72			$	197			$	57			$	80			$	136			$	273
Statistics for Operated Assets
Ethane equity sales (million gallons)			36				33				40				34				143				38				5				32				75
Non-ethane equity sales (million gallons)			39				32				29				41				141				37				5				24				66
NGL equity sales (million gallons)			75				65				69				75				284				75				10				56				141
Ethane production (million gallons)			36				33				40				35				144				38				5				32				75
Non-ethane production (million gallons)			31				27				34				29				121				33				7				30				70
NGL production (million gallons)			67				60				74				64				265				71				12				62				145
Petrochemical Services
Geismar ethylene sales volumes (million lbs)			2				213				404				447				1,066				423				391				419				1,233
Geismar ethylene margin ($/lb) (2)		$	—			$	.21			$	.16			$	.11			$	.15			$	.13			$	.15			$	.21			$	.16
Canadian propylene sales volumes (millions lbs)			39				38				44				40				161				33				8				46				87
Canadian alky feedstock sales volumes (million gallons)			7				6				6				7				26				7				2				6				15
Overland Pass Pipeline Company LLC (equity investment) – 100%
NGL Transportation volumes (Mbbls)			10,845				13,860				15,075				15,527				55,307				16,814				18,410				18,535				53,759

 

(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)

 

		2015																				2016
(Dollars in millions)		1st Qtr				2nd Qtr				3rd Qtr				4th Qtr				Year				1st Qtr				2nd Qtr				3rd Qtr				Year
Capital expenditures:
Central		$	69			$	75			$	66			$	42			$	252			$	38			$	16			$	22			$	76
Northeast G&P			179				148				136				116				579				65				53				45				163
Atlantic-Gulf			361				384				383				376				1,504				294				404				375				1,073
West			50				52				47				56				205				20				15				38				73
NGL & Petchem Services			75				55				59				63				252				46				28				13				87
Other			1				1				1				—				3				—				2				(2	)			—
Total*		$	735			$	715			$	692			$	653			$	2,795			$	463			$	518			$	491			$	1,472
Purchases of businesses (net of cash acquired):
Central		$	—			$	112			$	—			$	—			$	112			$	—			$	—			$	—			$	—
Total		$	—			$	112			$	—			$	—			$	112			$	—			$	—			$	—			$	—
Purchases of investments:
Central		$	1			$	10			$	16			$	31			$	58			$	39			$	19			$	26			$	84
Northeast G&P			59				388				13				30				490				20				37				95				152
Atlantic-Gulf			20				—				15				—				35				—				—				—				—
NGL & Petchem Services			3				2				1				5				11				4				3				2				9
Total		$	83			$	400			$	45			$	66			$	594			$	63			$	59			$	123			$	245
Summary:
Central		$	70			$	197			$	82			$	73			$	422			$	77			$	35			$	48			$	160
Northeast G&P			238				536				149				146				1,069				85				90				140				315
Atlantic-Gulf			381				384				398				376				1,539				294				404				375				1,073
West			50				52				47				56				205				20				15				38				73
NGL & Petchem Services			78				57				60				68				263				50				31				15				96
Other			1				1				1				—				3				—				2				(2	)			—
Total		$	818			$	1,227			$	737			$	719			$	3,501			$	526			$	577			$	614			$	1,717
Capital expenditures incurred, purchases of businesses (net of cash acquired), and purchases of investments:
Increases to property, plant, and equipment		$	645			$	731			$	673			$	600			$	2,649			$	498			$	485			$	446			$	1,429
Purchases of businesses (net of cash acquired)			—				112				—				—				112				—				—				—				—
Purchases of investments			83				400				45				66				594				63				59				123				245
Total		$	728			$	1,243			$	718			$	666			$	3,355			$	561			$	544			$	569			$	1,674
*Increases to property, plant, and equipment		$	645			$	731			$	673			$	600			$	2,649			$	498			$	485			$	446			$	1,429
Changes in related accounts payable and accrued liabilities			90				(16	)			19				53				146				(35	)			33				45				43
Capital expenditures		$	735			$	715			$	692			$	653			$	2,795			$	463			$	518			$	491			$	1,472

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Williams Partners L.P.

Reconciliation of Non-GAAP Measures

(UNAUDITED)

 

(Dollars in billions)						2016 Guidance
Williams Partners L.P.
Reconciliation of GAAP “Net Income (Loss)” to Non-GAAP “Modified EBITDA”, “Adjusted EBITDA”, and “Distributable cash flow”
Net income (loss)						$	0.9
Provision (benefit) for income taxes							(0.1	)
Interest expense							0.9
Equity (earnings) losses							(0.4	)
Impairment of equity-method investments							0.1
Proportional Modified EBITDA of equity-method investments							0.7
Depreciation and amortization expenses and accretion for asset retirement obligations							1.8
Modified EBITDA							3.9
Adjustments:
Severance and related costs		$	0.025
Potential rate refunds associated with rate case litigation			0.015
Merger and transition related expenses			0.005
Constitution Pipeline project development costs			0.008
Impairment of certain assets			0.389
Total EBITDA adjustments							0.4
Adjusted EBITDA							4.3
Maintenance capital expenditures (1)							(0.4	)
Interest expense (cash portion) (2)							(1.0	)
Income attributable to noncontrolling interests, cash taxes and other							(0.1	)
Distributable cash flow attributable to Partnership Operations						$	2.8

Notes:

 

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

 

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