Exhibit 99.1

 

DATE: Feb. 15, 2017

 

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

Williams Partners Reports 2016 Financial Results

 

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4Q 2016 Cash Flow from Operations of $1.597 billion, Up $1.034 billion Including Barnett Contract Restructure

 

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Full-Year 2016 Adjusted EBITDA of $4.427 billion, Up 8.3% vs. 2015

 

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Increased Fee-Based Revenues and Lowered Expenses for Full-Year 2016 as Additional Assets were Placed Into Service

 

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Full-Year 2016 DCF of $2.970 billion, Up $151 million, or 5.4% vs. 2015

 

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Financial Repositioning Strengthens Distribution Coverage, Enhances Credit Profile, Improves Cost of Capital, Removes Need to Access Public Equity Markets, Boosts Growth Outlook

TULSA, Okla. – Williams Partners L.P. (NYSE: WPZ) today announced its financial results for the three and 12 months ended Dec. 31, 2016.

 

Summary Financial Information		4Q								Full Year
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
(Unaudited)
GAAP Measures
Cash Flow from Operations		$	1,597			$	563			$	3,938			$	2,661
Net income (loss)		$	145			($	1,644	)		$	431			($	1,449	)
Net income (loss) per common unit		$	0.24			($	2.68	)		($	0.17	)		($	3.27	)
Non-GAAP Measures (1)
Adjusted EBITDA		$	1,113			$	1,064			$	4,427			$	4,089
DCF attributable to partnership operations		$	699			$	718			$	2,970			$	2,819
Cash distribution coverage ratio			.92x				.99x				1.01x				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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Fourth-Quarter and Full-Year 2016 Financial Results

Williams Partners reported unaudited fourth-quarter 2016 net income attributable to controlling interests of $145 million, a $1.789 billion improvement over the fourth-quarter 2015. The favorable change was driven by the absence of a $1.1 billion impairment of goodwill and $580 million of lower impairments of equity-method investments. The improvement also reflected lower operating and maintenance (O&M) and selling, general and administrative (SG&A) expenses.

For the year, Williams Partners reported unaudited net income attributable to controlling interests of $431 million, a $1.880 billion improvement compared to full-year 2015 results. The favorable change was driven by the absence of a $1.1 billion impairment of goodwill and $929 million of lower impairments of equity-method investments. The improvements also reflected an increase in olefins margins associated with the Geismar olefins plant, higher fee-based revenues, lower O&M and SG&A expenses and higher equity earnings. These favorable changes were partially offset by increased asset-impairment charges, a loss associated with the sale of our Canadian operations, a reduction of $119 million of insurance recoveries and higher interest expenses.

Williams Partners reported fourth-quarter 2016 Adjusted EBITDA of $1.113 billion, a $49 million increase over fourth-quarter 2015. The increase was due primarily to $48 million lower O&M and SG&A expenses and $17 million higher commodity margins. These increases were partially offset by $23 million due to a one-time, year-to-date true-up of amounts previously recognized during 2016 related to Barnett Shale minimum volume commitments caused by the Barnett re-contracting that occurred during the fourth quarter.

For the year, Williams Partners reported Adjusted EBITDA of $4.427 billion, a $338 million increase over full-year 2015 results. The increase is due primarily to $130 million lower O&M and SG&A expenses, $111 million higher olefins margins due primarily to a full year of Geismar operations, $93 million higher fee-based revenues primarily due to expansion projects and $47 million of higher proportional EBITDA from joint ventures. These favorable changes were partially offset by $43 million of other unfavorable changes including a $20 million unfavorable change in foreign currency exchange gains and losses related to our former Canadian operations.

Distributable Cash Flow and Distributions

For fourth-quarter 2016, Williams Partners generated $699 million in distributable cash flow (DCF) attributable to partnership operations, compared with $718 million in DCF attributable to partnership operations for the same period last year. The decrease is due primarily to a $33 million increase in maintenance capital and a $25 million increase in interest expense, partially offset by the previously described improvement in Adjusted EBITDA. For fourth-quarter 2016, the cash distribution coverage ratio was 0.92x.

For the year, the partnership generated $2.970 billion in DCF, an increase of $151 million over full-year 2015 DCF results. The increase was due primarily to the $338 million increase in Adjusted EBITDA described above, partially offset by $125 million higher interest expense and $39 million higher maintenance capital. For full-year 2016, the cash distribution coverage ratio was 1.01x.

On Feb. 10, 2017, Williams Partners paid a regular quarterly cash distribution of $0.85 per unit for its common unitholders of record at the close of business on Feb. 3, 2017.

CEO Perspective

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

“We realized strong cash flows from operations in 2016. The fact that Williams Partners delivered 8 percent year-over-year growth in Adjusted EBITDA demonstrates the strength of our proven natural gas-focused strategy. Our well-positioned natural gas infrastructure assets enabled us to once again organically grow fee-based revenues while our disciplined approach drove lower expenses even as we brought new assets online.

“The demand for natural gas for clean-power generation, heating, industrial use and LNG continues to increase as highlighted last month when Transco established record high one-day and three-day delivery volumes. We have construction underway on a number of Transco-expansion projects. And just this month, we successfully placed into service our Gulf Trace project, a 1.2 million dekatherm per day expansion of the Transco pipeline system to serve Cheniere Energy’s Sabine Pass Liquefaction export terminal in Louisiana. Gulf Trace is just one of the five Transco projects that are planned to be completed this year. This project was also brought in under budget and nearly six months ahead of its original planned in-service date.

 

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“In January, we took steps to strengthen our financial position and lower our cost of capital to match up with our peer-leading, high-quality, low-risk growth portfolio. We continue to fortify our focus on natural gas market fundamentals. Once the Geismar monetization process is completed, we expect to be at approximately 97 percent fee-based revenues driven by natural gas volumes. As a result, Williams and Williams Partners are positioned for long-term, sustainable growth.”

Business Segment Results

 

Williams Partners		Modified and Adjusted EBITDA
Amounts in millions		4Q 2016				4Q 2016								4Q 2015				4Q 2015								Full-Year 2016												Full-Year 2015
		Modified EBITDA				Adjust.				Adjusted EBITDA				Modified EBITDA				Adjust.				Adjusted EBITDA				Modified EBITDA				Adjust.				Adjusted EBITDA				Modified EBITDA				Adjust.				Adjusted EBITDA
Atlantic-Gulf		$	451			($	2	)		$	449			$	385			$	5			$	390			$	1,600			$	40			$	1,640			$	1,523			$	5			$	1,528
Central			340				(146	)			194				384				(165	)			219				807				105				912				840				9				899
NGL & Petchem Services			81				6				87				72				—				72				(23	)			383				360				321				(124	)			197
Northeast G&P			202				10				212				196				13				209				840				21				861				753				65				818
West			170				1				171				77				98				175				649				5				654				557				91				648
Other			(9	)			9				—				(2	)			1				(1	)			(9	)			9				—				9				(10	)			(1	)
Total		$	1,235			($	122	)		$	1,113			$	1,112			($	48	)		$	1,064			$	3,864			$	563			$	4,427			$	4,003			$	86			$	4,089

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

Atlantic-Gulf

For the fourth-quarter and full-year 2016, the Atlantic-Gulf operating area included the Transco interstate gas pipeline and a 41 percent interest in the Constitution interstate gas pipeline development project, which Williams Partners consolidates. The segment also included the partnership’s significant natural gas gathering and processing and crude oil production 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 $451 million for fourth-quarter 2016, compared with $385 million for fourth-quarter 2015. Adjusted EBITDA increased by $59 million to $449 million for the same time period. The increase in both measures was due primarily to $47 million higher fee-based revenues primarily from offshore projects and Transco expansion projects as well as $9 million of higher NGL margins.

For the year, Atlantic-Gulf reported Modified EBITDA of $1.600 billion, an increase of $77 million over full-year 2015. Adjusted EBITDA increased $112 million to $1.640 billion. The increase in Modified EBITDA was due primarily to $74 million higher fee-based revenues predominantly from Transco expansion projects and offshore expansions as well as $30 million higher proportional EBITDA from Discovery. Partially offsetting these increases were higher expenses primarily related to the net impact of new assets being placed into service and increased maintenance and modernization expenses. 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

For the fourth-quarter and full-year 2016, the Central operating area included 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. In 2016, Central provided gathering, treating and compression services to producers under long-term, fee-based contracts. The segment also includes a non-operated 50 percent interest in the Delaware Basin gas gathering system in the Mid-Continent region.

The Central operating area reported Modified EBITDA of $340 million for fourth-quarter 2016, a decrease of $44 million from fourth-quarter 2015. Adjusted EBITDA decreased by $25 million to $194 million. The unfavorable change in Modified EBITDA was due primarily to a $27 million reduction in fee-based revenues, which decreased primarily due to volume declines in the Barnett and Anadarko as well as a lower rate in the Barnett, Anadarko, and Eagle Ford areas.

 

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These decreases were partially offset by higher rates and volumes in the Haynesville Basin primarily attributable to the restructured contract with Chesapeake. Modified EBITDA was also favorably impacted by a $16 million decrease in O&M and SG&A expenses from fourth-quarter 2015. Adjusted EBITDA was unfavorably impacted by approximately $23 million due to a one-time, year-to-date true-up of amounts previously recognized during 2016 related to Barnett Shale minimum volume commitments caused by the Barnett re-contracting that occurred during the fourth quarter.

For the year, the Central operating area reported Modified EBITDA of $807 million, a decrease of $33 million from full-year 2015 results. Adjusted EBITDA increased $13 million to $912 million. The decrease in Modified EBITDA was due primarily to lower fee-based revenues and higher non-cash asset impairment charges. Consistent with the fourth-quarter explanation, fee revenues decreased primarily due to volume declines in the Barnett and Anadarko as well as a lower rate in the Barnett, Anadarko, and Eagle Ford areas. These decreases were partially offset by higher rates and volumes in the Haynesville primarily attributable to the restructured contract with Chesapeake. Full-year 2016 Modified EBITDA was also favorably impacted by lower O&M and SG&A expenses due to cost-reduction efforts and the absence of prior-year merger and transition costs as well as higher proportional EBITDA from joint-venture operations. Adjusted EBITDA was not impacted by the impairment charges or merger and transition costs.

NGL & Petchem Services

In 2016, NGL & Petchem Services operating area included 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 included 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 $81 million for fourth-quarter 2016, compared with $72 million for fourth-quarter 2015. Adjusted EBITDA increased by $15 million to $87 million. The increase in Modified EBITDA was due primarily to $7 million lower O&M and SG&A expenses and $6 million higher commodity margins. Partially offsetting these increases were $8 million lower fee-based revenues.

For the year, NGL & Petchem Services operating area reported Modified EBITDA of ($23) million compared with $321 million during full-year 2015. Adjusted EBITDA increased $163 million to $360 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 $119 million of lower business-interruption proceeds. Partially offsetting these unfavorable items were $111 million favorable olefins margins, primarily related to higher volumes and prices at the Geismar olefins plant, and a $30 million increase in fee-based revenues primarily from our former Canadian operations. 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 $202 million for fourth-quarter 2016, compared with $196 million for fourth-quarter 2015. Adjusted EBITDA increased $3 million to $212 million. The increase in Modified EBITDA was due primarily to $15 million lower O&M and SG&A expenses and $12 million higher fee-based revenues. Partially offsetting the increases was $18 million lower proportional joint-venture EBITDA.

For the year, Northeast G&P operating area reported Modified EBITDA of $840 million compared with $753 million for full-year 2015. Adjusted EBITDA increased $43 million to $861 million. The increase in Modified EBITDA was driven by $37 million higher fee-based revenues, $36 million reduced O&M expenses, and a reduced level of non-cash impairment charges. Adjusted EBITDA excludes the impact of non-cash impairment charges.

 

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West

In 2016, the West operating area included 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 $170 million for fourth-quarter 2016, compared with $77 million for fourth-quarter 2015. Adjusted EBITDA of $171 million is $4 million lower than the same period in 2015. The increase in Modified EBITDA was driven primarily by the absence of $97 million non-cash impairment charges incurred in 2015. The favorable change in Modified EBITDA was also driven by $7 million lower O&M and SG&A expenses, $4 million higher commodity margins, and $11 million lower fee-based revenues. Adjusted EBITDA excludes the prior-year non-cash impairment charges.

For the year, the West operating area reported Modified EBITDA of $649 million compared with $557 million for full-year 2015. Adjusted EBITDA increased $6 million to $654 million. The increase in Modified EBITDA was driven primarily by the absence of $97 million non-cash impairment charges incurred in 2015. The favorable change in Modified EBITDA was also driven by $26 million lower O&M and SG&A expenses and $17 million lower fee-based revenues. Adjusted EBITDA excludes the prior-year non-cash impairment charges.

Financial Repositioning and Guidance

On Jan. 9, 2017, Williams Partners and Williams (NYSE: WMB) announced a financial repositioning plan designed to strengthen Williams Partners’ distribution coverage, enhance the partnership’s credit profile, improve cost of capital, remove the partnership’s need to access public equity markets for the next several years and boost its growth outlook. The plan included the permanent waiver of Incentive Distribution Rights (IDRs) held by Williams in exchange for 289 million newly issued Williams Partners’ common units which closed on Jan. 9.

Also as part of this plan, Williams purchased 58.7 million newly issued Williams Partners common units with total proceeds of $2.1 billion. Williams Partners used $600 million of these proceeds to repay 7.25 percent notes that matured on Feb. 1, 2017 and also announced that on Feb. 23, 2017 it will redeem all of its $750 million 6.125 percent senior notes due 2022. We expect the balance of the proceeds to be used to fund capital and investment expenditures. Also as previously announced, Williams expects to raise more than $2 billion in after-tax proceeds from planned asset monetizations of Geismar and other select assets which are not core to our strategy. We expect proceeds from these monetizations will be used for additional debt reduction and to fund capital and investment expenditures.

Additionally, the partnership announced its intent to pay a regular quarterly cash distribution of $0.60 per common unit beginning with the next quarterly distribution for the quarter ending March 31, 2017. The partnership expects to pay $2.40 per common unit for 2017 and is targeting 5 to 7 percent annual growth over the next several years.

Guidance for 2017 (as previously announced on Jan. 9, 2017) is unchanged.

Williams Partners’ Year-End 2016 Materials to be Posted Shortly; Q&A Webcast Scheduled for Tomorrow

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

Williams Partners and Williams will host a joint Q&A live webcast on Thursday, Feb. 16 at 9:30 a.m. EST. A limited number of phone lines will be available at (800) 946-0709. International callers should dial (719) 325-2376. The conference ID is 7387877. 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-K

The partnership plans to file its 2016 Form 10-K with the Securities and Exchange Commission next week. Once filed, the document will be available on both the SEC and Williams Partners’ websites.

Definitions of Non-GAAP Measures

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

 

 

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

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

We define distributable cash flow as adjusted EBITDA less maintenance capital expenditures, cash portion of interest expense, income attributable to non-controlling 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 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 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 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:

 

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Levels of cash distributions 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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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, natural gas liquids, and olefins 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 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:

 

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Whether we will produce sufficient cash flows to provide the level of cash distributions that Williams expects;

 

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

 

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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 midstream 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 of alternative energy sources;

 

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

 

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

 

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Our allocated 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 “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 our risk factors in addition to the other information in this report. If any of such risks were actually to occur, our business, results of operations and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment.

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

(UNAUDITED)

Final

December 31, 2016

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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				4th 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			$	166			$	519
Provision (benefit) for income taxes			3				—				1				(3	)			1				1				(80	)			(6	)			5				(80	)
Interest expense			192				203				205				211				811				229				231				229				227				916
Equity (earnings) losses			(51	)			(93	)			(92	)			(99	)			(335	)			(97	)			(101	)			(104	)			(95	)			(397	)
Impairment of equity-method investments			—				—				461				898				1,359				112				—				—				318				430
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				180				754
Impairment of goodwill			—				—				—				1,098				1,098				—				—				—				—				—
Depreciation and amortization expenses			419				419				423				441				1,702				435				432				426				427				1,720
Accretion for asset retirement obligations associated with nonregulated operations			7				9				5				7				28				7				9				8				7				31
Modified EBITDA			817				1,053				1,021				1,112				4,003				955				604				1,070				1,235				3,864
Adjustments
Estimated minimum volume commitments			55				55				65				(175	)			—				60				64				70				(194	)			—
Severance and related costs			—				—				—				—				—				25				—				—				12				37
Potential rate refunds associated with rate case litigation			—				—				—				—				—				15				—				—				—				15
ACMP Merger and transition-related expenses			32				14				2				2				50				5				—				—				—				5
Constitution Pipeline project development costs			—				—				—				—				—				—				8				11				9				28
Share of impairment at equity-method investments			8				1				17				7				33				—				—				6				19				25
Geismar Incident adjustment for insurance and timing			—				(126	)			—				—				(126	)			—				—				—				(7	)			(7	)
Loss related to Geismar Incident			1				1				—				—				2				—				—				—				—				—
Impairment of certain assets			3				24				2				116				145				—				389				—				22				411
Organizational realignment-related costs			—				—				—				—				—				—				—				—				24				24
Loss related to Canada disposition			—				—				—				—				—				—				—				32				2				34
Gain on asset retirement			—				—				—				—				—				—				—				—				(11	)			(11	)
Loss (recovery) related to Opal incident			1				—				(8	)			1				(6	)			—				—				—				—				—
Gain on extinguishment of debt			—				(14	)			—				—				(14	)			—				—				—				—				—
Expenses associated with strategic asset monetizations			—				—				—				—				—				—				—				—				2				2
Expenses associated with strategic alternatives			—				—				1				1				2				—				—				—				—				—
Total EBITDA adjustments			100				(45	)			79				(48	)			86				105				461				119				(122	)			563
Adjusted EBITDA			917				1,008				1,100				1,064				4,089				1,060				1,065				1,189				1,113				4,427
Maintenance capital expenditures (1)			(54	)			(80	)			(114	)			(114	)			(362	)			(58	)			(75	)			(121	)			(147	)			(401	)
Interest expense (cash portion) (2)			(204	)			(207	)			(219	)			(214	)			(844	)			(241	)			(245	)			(244	)			(239	)			(969	)
Cash taxes			(1	)			—				—				—				(1	)			—				—				—				(3	)			(3	)
Income attributable to noncontrolling interests (3)			(23	)			(32	)			(27	)			(29	)			(111	)			(29	)			(13	)			(31	)			(27	)			(100	)
WPZ restricted stock unit non-cash compensation			7				6				7				7				27				7				5				2				2				16
Plymouth incident adjustment			4				6				7				4				21				—				—				—				—				—
Distributable cash flow attributable to Partnership Operations (4)			646				701				754				718				2,819				739				737				795				699				2,970
Total cash distributed (5)		$	725			$	723			$	723			$	725			$	2,896			$	725			$	725			$	734			$	762			$	2,946
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				0.92				1.01
Net income (loss) divided by Total cash distributed			0.15				0.46				(0.23	)			(2.26	)			(0.47	)			0.11				(0.11	)			0.48				0.22				0.18

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)	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 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. Cash distributions for the fourth quarter of 2016 have been decreased by $50 million 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)

 

		2015																				2016
(Dollars in millions)		1st Qtr				2nd Qtr				3rd Qtr				4th Qtr				Year				1st Qtr				2nd Qtr				3rd Qtr				4th Qtr				Year
Modified EBITDA:
Central		$	133			$	160			$	163			$	384			$	840			$	157			$	134			$	176			$	340			$	807
Northeast G&P			185				183				189				196				753				214				216				208				202				840
Atlantic-Gulf			335				389				414				385				1,523				376				357				416				451				1,600
West			161				150				169				77				557				155				158				166				170				649
NGL & Petchem Services			6				158				85				72				321				53				(261	)			104				81				(23	)
Other			(3	)			13				1				(2	)			9				—				—				—				(9	)			(9	)
Total Modified EBITDA		$	817			$	1,053			$	1,021			$	1,112			$	4,003			$	955			$	604			$	1,070			$	1,235			$	3,864
Adjustments:
Central
Estimated minimum volume commitments		$	55			$	55			$	65			$	(175	)		$	—			$	60			$	64			$	70			$	(194	)		$	—
Severance and related costs			—				—				—				—				—				6				—				—				2				8
ACMP Merger and transition costs			30				14				2				2				48				3				—				—				—				3
Impairment of certain assets			—				3				—				8				11				—				48				—				22				70
Organizational realignment-related costs			—				—				—				—				—				—				—				—				24				24
Total Central adjustments			85				72				67				(165	)			59				69				112				70				(146	)			105
Northeast G&P
Severance and related costs			—				—				—				—				—				3				—				—				—				3
Share of impairment at equity-method investments			8				1				17				7				33				—				—				6				10				16
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				10				21
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
Impairment of certain assets			—				—				—				5				5				—				—				—				—				—
Gain on asset retirement			—				—				—				—				—				—				—				—				(11	)			(11	)
Total Atlantic-Gulf adjustments			—				—				—				5				5				23				8				11				(2	)			40
West
Severance and related costs			—				—				—				—				—				4				—				—				1				5
Impairment of certain assets			—				—				—				97				97				—				—				—				—				—
Loss (recovery) related to Opal incident			1				—				(8	)			1				(6	)			—				—				—				—				—
Total West adjustments			1				—				(8	)			98				91				4				—				—				1				5
NGL & Petchem Services
Impairment of certain assets			—				—				—				—				—				—				341				—				—				341
Loss related to Canada disposition			—				—				—				—				—				—				—				32				2				34
Share of impairment at equity-method investments			—				—				—				—				—				—				—				—				9				9
Severance and related costs			—				—				—				—				—				4				—				—				—				4
Expenses associated with strategic asset monetizations			—				—				—				—				—				—				—				—				2				2
Loss related to Geismar Incident			1				1				—				—				2				—				—				—				—				—
Geismar Incident adjustment for insurance and timing			—				(126	)			—				—				(126	)			—				—				—				(7	)			(7	)
Total NGL & Petchem Services adjustments			1				(125	)			—				—				(124	)			4				341				32				6				383
Other
Severance and related costs			—				—				—				—				—				—				—				—				9				9
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	)			—				—				—				9				9
Total Adjustments		$	100			$	(45	)		$	79			$	(48	)		$	86			$	105			$	461			$	119			$	(122	)		$	563
Adjusted EBITDA:
Central		$	218			$	232			$	230			$	219			$	899			$	226			$	246			$	246			$	194			$	912
Northeast G&P			196				205				208				209				818				219				216				214				212				861
Atlantic-Gulf			335				389				414				390				1,528				399				365				427				449				1,640
West			162				150				161				175				648				159				158				166				171				654
NGL & Petchem Services			7				33				85				72				197				57				80				136				87				360
Other			(1	)			(1	)			2				(1	)			(1	)			—				—				—				—				—
Total Adjusted EBITDA		$	917			$	1,008			$	1,100			$	1,064			$	4,089			$	1,060			$	1,065			$	1,189			$	1,113			$	4,427

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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				4th Qtr				Year
Revenues:
Service revenues		$	1,192			$	1,231			$	1,232			$	1,480			$	5,135			$	1,226			$	1,210			$	1,252			$	1,485			$	5,173
Product sales			519				599				560				518				2,196				428				530				655				705				2,318
Total revenues			1,711				1,830				1,792				1,998				7,331				1,654				1,740				1,907				2,190				7,491
Costs and expenses:
Product costs			463				494				426				396				1,779				317				403				463				545				1,728
Operating and maintenance expenses			380				431				394				420				1,625				382				386				385				395				1,548
Depreciation and amortization expenses			419				419				423				441				1,702				435				432				426				427				1,720
Selling, general, and administrative expenses			193				164				156				171				684				181				139				147				163				630
Impairment of goodwill			—				—				—				1,098				1,098				—				—				—				—				—
Net insurance recoveries - Geismar Incident			—				(126	)			—				—				(126	)			—				—				—				(7	)			(7	)
Impairment of certain assets			3				24				2				116				145				6				396				1				54				457
Other (income) expense - net			14				14				5				8				41				24				24				59				11				118
Total costs and expenses			1,472				1,420				1,406				2,650				6,948				1,345				1,780				1,481				1,588				6,194
Operating income (loss)			239				410				386				(652	)			383				309				(40	)			426				602				1,297
Equity earnings (losses)			51				93				92				99				335				97				101				104				95				397
Impairment of equity-method investments			—				—				(461	)			(898	)			(1,359	)			(112	)			—				—				(318	)			(430	)
Other investing income (loss) - net			1				—				—				1				2				—				1				28				—				29
Interest incurred			(209	)			(215	)			(216	)			(224	)			(864	)			(240	)			(239	)			(236	)			(234	)			(949	)
Interest capitalized			17				12				11				13				53				11				8				7				7				33
Other income (expense) - net			16				32				22				23				93				15				12				16				19				62
Income (loss) before income taxes			115				332				(166	)			(1,638	)			(1,357	)			80				(157	)			345				171				439
Provision (benefit) for income taxes			3				—				1				(3	)			1				1				(80	)			(6	)			5				(80	)
Net income (loss)			112				332				(167	)			(1,635	)			(1,358	)			79				(77	)			351				166				519
Less: Net income attributable to noncontrolling interests			23				32				27				9				91				29				13				25				21				88
Net income (loss) attributable to controlling interests		$	89			$	300			$	(194	)		$	(1,644	)		$	(1,449	)		$	50			$	(90	)		$	326			$	145			$	431
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			$	145			$	431
Allocation of net income (loss) to general partner (1)			195				216				1				(28	)			384				202				207				72				—				517
Allocation of net income (loss) to Class B units (1)			(2	)			1				(5	)			(39	)			(46	)			(4	)			(8	)			7				2				12
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			$	143			$	(98	)
Diluted earnings (loss) per common unit:
Net income (loss) per common unit (1)		$	(0.34	)		$	0.14			$	(0.32	)		$	(2.68	)		$	(3.27	)		$	(0.25	)		$	(0.49	)		$	0.42			$	0.24			$	(0.17	)
Weighted average number of common units outstanding (thousands)			507,001				587,088				586,722				587,581				567,275				588,562				588,607				591,567				601,738				592,519
Cash distributions per common unit		$	0.85			$	0.85			$	0.85			$	0.85			$	3.40			$	0.85			$	0.85			$	0.85			$	0.85			$	3.40

 

(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				4th Qtr				Year
Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue		$	242			$	247			$	256			$	486				1,231			$	240			$	243			$	240			$	458			$	1,181
Other fee revenues			10				18				14				14				56				15				15				15				15			$	60
			252				265				270				500				1,287				255				258				255				473				1,241
Intrasegment eliminations			—				—				—				—				—				—				—				—				—				—
Total revenues			252				265				270				500				1,287				255				258				255				473				1,241
Segment costs and expenses:
Other segment costs and expenses (1)			127				112				116				117				472				108				88				91				100				387
Impairment of certain assets			—				3				—				8				11				(1	)			48				1				47				95
Intrasegment eliminations			—				—				—				—				—				—				—				—				—				—
Total segment costs and expenses			127				115				116				125				483				107				136				92				147				482
Proportional Modified EBITDA of equity-method investments			8				10				9				9				36				9				12				13				14				48
Modified EBITDA			133				160				163				384				840				157				134				176				340				807
Adjustments			85				72				67				(165	)			59				69				112				70				(146	)			105
Adjusted EBITDA		$	218			$	232			$	230			$	219			$	899			$	226			$	246			$	246			$	194			$	912
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				2.42				2.47

 

(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				4th Qtr				Year
Revenues:
Service revenues:
Nonregulated gathering and processing fee-based revenue		$	185			$	183			$	170			$	183			$	721			$	186			$	182			$	180			$	184			$	732
Other fee revenues			11				33				25				20				89				26				29				29				31				115
Product sales:
NGL sales from gas processing			2				3				3				3				11				4				3				3				4				14
Marketing sales			36				32				23				25				116				20				30				40				59				149
			234				251				221				231				937				236				244				252				278				1,010
Intrasegment eliminations			—				—				—				—				—				(1	)			(3	)			(2	)			(3	)			(9	)
Total revenues			234				251				221				231				937				235				241				250				275				1,001
Segment costs and expenses:
NGL cost of goods sold			1				1				—				2				4				1				2				1				2				6
Marketing cost of goods sold			36				32				25				24				117				20				32				41				60				153
Other segment costs and expenses (1)			85				108				86				101				380				94				86				90				89				359
Impairment of certain assets			3				21				2				6				32				4				4				—				5				13
Intrasegment eliminations			—				—				—				—				—				(1	)			(3	)			(1	)			(3	)			(8	)
Total segment costs and expenses			125				162				113				133				533				118				121				131				153				523
Proportional Modified EBITDA of equity-method investments			76				94				81				98				349				97				96				89				80				362
Modified EBITDA			185				183				189				196				753				214				216				208				202				840
Adjustments			11				22				19				13				65				5				—				6				10				21
Adjusted EBITDA		$	196			$	205			$	208			$	209			$	818			$	219			$	216			$	214			$	212			$	861
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				3.19				3.21
Gathering volumes (Bcf per day) - Non-consolidated (3)			3.00				3.05				3.10				3.06				3.05				3.21				3.16				3.08				3.20				3.16
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				0.37				0.33
Ethane equity sales (Mbbls/d)			1				3				4				6				4				6				4				3				3				4
Non-ethane equity sales (Mbbls/d)			1				1				1				1				1				1				1				1				1				1
NGL equity sales (Mbbls/d)			2				4				5				7				5				7				5				4				4				5
Ethane production (Mbbls/d)			1				11				13				13				10				14				18				22				20				18
Non-ethane production (Mbbls/d)			12				15				16				11				13				11				12				16				15				14
NGL production (Mbbls/d)			13				26				29				24				23				25				30				38				35				32

 

(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.

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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				4th Qtr				Year
Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue		$	95			$	106			$	102			$	94			$	397			$	82			$	67			$	120			$	127			$	396
Regulated transportation revenue			308				312				328				337				1,285				349				331				339				347				1,366
Other fee revenues			29				29				29				32				119				14				32				31				36				113
Product sales:
NGL sales from gas processing			11				7				11				10				39				8				11				25				31				75
Marketing sales			87				80				63				64				294				45				75				78				83				281
Other sales			—				1				—				—				1				—				—				3				5				8
Tracked revenues			49				56				63				42				210				38				39				51				39				167
			579				591				596				579				2,345				536				555				647				668				2,406
Intrasegment eliminations			—				—				(1	)			—				(1	)			(1	)			(2	)			(2	)			—				(5	)
Total revenues			579				591				595				579				2,344				535				553				645				668				2,401
Segment costs and expenses:
NGL cost of goods sold			4				2				3				3				12				3				4				15				15				37
Marketing cost of goods sold			87				80				63				63				293				45				74				77				83				279
Other cost of goods sold			—				—				—				—				—				—				—				2				1				3
Impairment of certain assets			—				—				—				5				5				1				—				—				—				1
Other segment costs and expenses (1)			142				131				131				155				559				139				149				161				157				606
Tracked costs			49				56				63				42				210				38				39				51				39				167
Intrasegment eliminations			—				—				(1	)			—				(1	)			(1	)			(2	)			(2	)			—				(5	)
Total segment costs and expenses			282				269				259				268				1,078				225				264				304				295				1,088
Proportional Modified EBITDA of equity-method investments			38				67				78				74				257				66				68				75				78				287
Modifed EBITDA			335				389				414				385				1,523				376				357				416				451				1,600
Adjustments			—				—				—				5				5				23				8				11				(2	)			40
Adjusted EBITDA		$	335			$	389			$	414			$	390			$	1,528			$	399			$	365			$	427			$	449			$	1,640
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				0.53				0.41
Gathering volumes (Bcf per day) - Non-consolidated (3)			0.34				0.62				0.63				0.59				0.55				0.53				0.54				0.60				0.60				0.56
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				0.78				0.72
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				0.60				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			$	.35			$	.31
NGL margin ($/gallon)		$	.26			$	.41			$	.32			$	.26			$	.30			$	.21			$	.18			$	.16			$	.20			$	.19
Ethane equity sales (Mbbls/d)			3				1				2				3				2				2				6				6				8				5
Non-ethane equity sales (Mbbls/d)			4				3				5				4				4				4				4				11				12				8
NGL equity sales (Mbbls/d)			7				4				7				7				6				6				10				17				20				13
Ethane production (Mbbls/d)			10				8				9				12				10				13				17				16				19				16
Non-ethane production (Mbbls/d)			25				23				24				22				24				20				20				31				30				25
NGL production (Mbbls/d)			35				31				33				34				34				33				37				47				49				41
Non-consolidated (3)
NGL equity sales (Mbbls/d)			5				6				5				5				5				5				5				5				5				5
NGL production (Mbbls/d)			16				21				21				19				19				17				19				21				21				20
Transcontinental Gas Pipe Line
Throughput (Tbtu)			1,005.1				784.9				803.6				779.3				3,372.9				927.2				815.9				878.1				881.5				3,502.7
Avg. daily transportation volumes (Tbtu)			11.2				8.6				8.7				8.5				9.2				10.2				9.0				9.5				9.6				9.6
Avg. daily firm reserved capacity (Tbtu)			10.5				11.0				11.5				11.8				11.2				12.0				11.5				11.6				11.9				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				4th Qtr				Year
Revenues:
Service revenues:
Nonregulated gathering & processing fee-based revenue		$	138			$	138			$	138			$	147			$	561			$	136			$	137			$	134			$	134			$	541
Regulated transportation revenue			116				112				115				117				460				118				111				114				117				460
Other fee revenues			8				7				10				7				32				9				8				9				9				35
Product sales:
NGL sales from gas processing			48				49				43				47				187				38				54				53				58				203
Marketing sales			10				15				15				13				53				11				21				15				17				64
Other sales			6				4				4				3				17				3				3				2				3				11
Tracked revenues			—				1				—				1				2				—				1				—				—				1
			326				326				325				335				1,312				315				335				327				338				1,315
Intrasegment eliminations			—				—				—				—				—				—				(2	)			(1	)			—				(3	)
Total revenues			326				326				325				335				1,312				315				333				326				338				1,312
Segment costs and expenses:
NGL cost of goods sold			23				20				20				19				82				18				21				26				26				91
Marketing cost of goods sold			10				15				15				13				53				11				21				14				17				63
Other cost of goods sold			3				2				3				2				10				2				1				1				1				5
Other segment costs and expenses (1)			129				138				118				126				511				127				132				120				123				502
Impairment of certain assets			—				—				—				97				97				2				1				—				1				4
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				168				663
Proportional Modified EBITDA of equity-method investments			—				—				—				—				—				—				—				—				—				—
Modifed EBITDA			161				150				169				77				557				155				158				166				170				649
Adjustments			1				—				(8	)			98				91				4				—				—				1				5
Adjusted EBITDA		$	162			$	150			$	161			$	175			$	648			$	159			$	158			$	166			$	171			$	654
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				2.17				2.07				2.15
Plant inlet natural gas volumes (Bcf per day)			2.58				2.55				2.49				2.47				2.52				2.51				2.51				2.48				2.32				2.45
Ethane equity sales (Mbbls/d)			1				1				1				1				1				4				15				6				4				7
Non-ethane equity sales (Mbbls/d)			20				20				19				20				20				20				22				23				21				21
NGL equity sales (Mbbls/d)			21				21				20				21				21				24				37				29				25				28
Ethane margin ($/gallon)		$	.39			$	.14			$	.28			$	.40			$	.27			$	.03			$	.00			$	.00			$	.00			$	.01
Non-ethane margin ($/gallon)		$	.34			$	.37			$	.29			$	.35			$	.34			$	.26			$	.39			$	.31			$	.41			$	.34
NGL margin ($/gallon)		$	.34			$	.35			$	.29			$	.35			$	.33			$	.22			$	.23			$	.24			$	.34			$	.26
Ethane production (Mbbls/d)			9				11				10				8				9				12				25				10				9				14
Non-ethane production (Mbbls/d)			63				65				66				65				65				64				66				65				62				64
NGL production (Mbbls/d)			72				76				76				73				74				76				91				75				71				78
Northwest Pipeline LLC
Throughput (Tbtu)			202.7				183.0				177.9				199.2				762.8				205.6				168.0				161.9				191.6				727.1
Avg. daily transportation volumes (Tbtu)			2.3				2.0				1.9				2.2				2.1				2.3				1.8				1.8				2.1				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				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				4th Qtr				Year
Revenues:
Service revenue:
Nonregulated gathering & processing fee-based revenue		$	7			$	10			$	11			$	11			$	39			$	11			$	12			$	12			$	10			$	45
Other fee-based revenues			41				42				47				46				176				47				60				54				39				200
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				160				649
Marketing sales			378				372				337				341				1,428				285				348				427				526				1,586
Other sales			4				4				1				4				13				2				3				4				2				11
			529				608				589				570				2,296				498				577				715				737				2,527
Intrasegment eliminations			(54	)			(61	)			(60	)			(61	)			(236	)			(54	)			(50	)			(82	)			(71	)			(257	)
Total revenues			475				547				529				509				2,060				444				527				633				666				2,270
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				86				312
Marketing cost of goods sold			381				376				340				340				1,437				287				354				423				517				1,581
Other cost of goods sold			6				4				2				5				17				4				2				5				2				13
Net insurance recoveries - Geismar Incident			—				(126	)			—				—				(126	)			—				—				—				(7	)			(7	)
Impairment of certain assets			—				—				—				—				—				—				343				—				1				344
Other segment costs and expenses (1)			66				88				71				71				296				94				75				106				65				340
Intrasegment eliminations			(54	)			(61	)			(60	)			(61	)			(236	)			(54	)			(50	)			(82	)			(71	)			(257	)
Total segment costs and expenses			480				398				456				447				1,781				408				803				546				593				2,350
Proportional Modified EBITDA of equity-method investments			11				9				12				10				42				17				15				17				8				57
Modified EBITDA			6				158				85				72				321				53				(261	)			104				81				(23	)
Adjustments			1				(125	)			—				—				(124	)			4				341				32				6				383
Adjusted EBITDA		$	7			$	33			$	85			$	72			$	197			$	57			$	80			$	136			$	87			$	360
Statistics for Operated Assets
Ethane equity sales (Mbbls/d)			10				9				10				9				9				10				1				8				—				7
Non-ethane equity sales (Mbbls/d)			10				8				7				11				9				10				1				6				—				6
NGL equity sales (Mbbls/d)			20				17				17				20				18				20				2				14				—				13
Ethane production (Mbbls/d)			10				9				10				9				9				10				1				8				—				7
Non-ethane production (Mbble/d)			8				7				9				8				8				8				2				8				—				6
NGL production (Mbbls/d)			18				16				19				17				17				18				3				16				—				13
Petrochemical Services
Geismar ethylene sales volumes (million lbs)			2				213				404				447				1,066				423				391				419				405				1,638
Geismar ethylene margin ($/lb) (2)		$	—			$	.21			$	.16			$	.11			$	.15			$	.13			$	.15			$	.21			$	.15			$	.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				18,078				71,837

 

(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				4th Qtr				Year
Capital expenditures:
Central		$	69			$	75			$	66			$	42			$	252			$	38			$	16			$	22			$	17			$	93
Northeast G&P			179				148				136				116				579				65				53				45				54				217
Atlantic-Gulf			361				384				383				376				1,504				294				404				375				342				1,415
West			50				52				47				56				205				20				15				38				51				124
NGL & Petchem Services			75				55				59				63				252				46				28				13				8				95
Other			1				1				1				—				3				—				2				(2	)			—				—
Total*		$	735			$	715			$	692			$	653			$	2,795			$	463			$	518			$	491			$	472			$	1,944
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			$	21			$	105
Northeast G&P			59				388				13				30				490				20				37				(18	)			23				62
Atlantic-Gulf			20				—				15				—				35				—				—				—				—				—
NGL & Petchem Services			3				2				1				5				11				4				3				2				1				10
Total		$	83			$	400			$	45			$	66			$	594			$	63			$	59			$	10			$	45			$	177
Summary:
Central		$	70			$	197			$	82			$	73			$	422			$	77			$	35			$	48			$	38			$	198
Northeast G&P			238				536				149				146				1,069				85				90				27				77				279
Atlantic-Gulf			381				384				398				376				1,539				294				404				375				342				1,415
West			50				52				47				56				205				20				15				38				51				124
NGL & Petchem Services			78				57				60				68				263				50				31				15				9				105
Other			1				1				1				—				3				—				2				(2	)			—				—
Total		$	818			$	1,227			$	737			$	719			$	3,501			$	526			$	577			$	501			$	517			$	2,121
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			$	442			$	1,871
Purchases of businesses (net of cash acquired)			—				112				—				—				112				—				—				—				—				—
Purchases of investments			83				400				45				66				594				63				59				10				45				177
Total		$	728			$	1,243			$	718			$	666			$	3,355			$	561			$	544			$	456			$	487			$	2,048
*    Increases to property, plant, and equipment		$	645			$	731			$	673			$	600			$	2,649			$	498			$	485			$	446			$	442			$	1,871
Changes in related accounts payable and accrued liabilities			90				(16	)			19				53				146				(35	)			33				45				30				73
Capital expenditures		$	735			$	715			$	692			$	653			$	2,795			$	463			$	518			$	491			$	472			$	1,944

---

Selected Financial Information

(UNAUDITED)

 

		2015																2016
(Dollars in millions)		1st Qtr				2nd Qtr				3rd Qtr				4th Qtr				1st Qtr				2nd Qtr				3rd Qtr				4th Qtr
Cash and cash equivalents		$	277			$	186			$	110			$	96			$	125			$	101			$	68			$	145
Capital structure:
Debt:
Commercial paper		$	—			$	1,743			$	1,530			$	499			$	135			$	196			$	2			$	93
Current		$	801			$	378			$	377			$	176			$	976			$	786			$	785			$	785
Noncurrent		$	17,025			$	16,648			$	17,144			$	19,001			$	18,504			$	19,116			$	18,918			$	17,685

---

WPZ Reconciliation of GAAP “Net Income (Loss)” to Non-GAAP “Modified EBITDA”,

“Adjusted EBITDA” and “Distributable Cash Flow”

 

(Dollars in billions, except coverage ratios)		2017 Guidance (1)
Net income (loss)		$	1.7
Provision (benefit) for income taxes			—
Interest expense			0.9
Equity (earnings) losses			(0.5	)
Proportional Modified EBITDA of equity-method investments			0.7
Depreciation and amortization expenses and accretion for asset retirement obligations associated with nonregulated operations			1.8
Modified EBITDA (2)			4.6
Adjustments:
Total EBITDA adjustments			—
Adjusted EBITDA (2)			4.6
Maintenance capital expenditures (3)			(0.5	)
Interest expense (cash portion) (4)			(0.9	)
Remove amortization associated with Barnett & MidCon contract restructure prepayments (5)			(0.2	)
Income attributable to noncontrolling interests, cash taxes and other			(0.2	)
Distributable cash flow attributable to Partnership Operations (6)			2.8
Total cash distributed		$	2.3
Cash Coverage Ratio (Distributable cash flow attributable to Partnership Operations / Total cash distributed) (6)			1.2x

Notes:

 

(1)	Assumes 2017 WTI oil price of approximately $55 per barrel and Henry Hub natural gas price of approximately $3.35 per mmbtu.

(2)	Includes full year of Geismar operations. Also includes amortization of $240 million associated with the $820 million Barnett & MidCon contract restructure prepayments.

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

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

(5)	Amortization of $240 million associated with the $820 million Barnett & MidCon contract restructure prepayments.

(6)	Includes full year of Geismar operations. Excludes amortization of $240 million associated with the $820 million Barnett & MidCon contract restructure prepayments.