TULSA, Okla.--(BUSINESS WIRE)--

Williams Partners L.P. (NYSE: WPZ) today announced its financial results for the three and 12 months ended Dec. 31, 2017.

Fourth-Quarter and Full-Year 2017 Highlights

• 4Q 2017 Net Income (Loss) of ($342) Million - Impacted by $713 million of Non-Cash Charges Related to Tax Cuts and Jobs Act of 2017
• Increased 4Q & Full-Year 2017 Adjusted EBITDA to $1.150 Billion and $4.472 Billion Respectively, Despite over $3 Billion in Asset Sales Since September 2016
• Cash Distribution Coverage Ratio of 1.22x for 4Q 2017; 1.23x for Full-Year 2017
• Placed Transco Expansions New York Bay and Virginia Southside II into Service in 4Q 2017 - Completing Transco's 2017 "Big 5" Expansion Projects
• Williams Partners Improved Credit Profile, Reducing Net Debt by $2.8 Billion from Jan. 1, 2017 through Dec. 31, 2017
• Williams Partners Exceeded Midpoint of Financial Guidance Targets for 2017, Guidance for 2018 DCF, Distribution Growth (5 to 7%) and Coverage Remain on Target

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.			2017				2016			2017			2016
GAAP Measures
Cash Flow from Operations (1)			$737				$1,597			$2,840			$3,948
Net income (loss)			($342	)			$145			$871			$431
Net income (loss) per common unit			($0.35	)			$0.24			$0.90			($0.17	)
Non-GAAP Measures (2)
Adjusted EBITDA			$1,150				$1,113			$4,472			$4,427
DCF attributable to partnership operations			$702				$699			$2,821			$2,970
Cash distribution coverage ratio			1.22x				0.92x			1.23x			1.01x

(1)		Cash Flow from Operations was higher in 2016, due primarily to the receipt of $820 million in cash in the fourth quarter of 2016 associated with certain contract restructurings and prepayments.
(2)		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.

Fourth-Quarter and Full-Year 2017 Financial Results

Williams Partners reported unaudited fourth-quarter 2017 net income (loss) attributable to controlling interests of ($342) million, a $487 million decrease from fourth-quarter 2016. The unfavorable change was driven primarily by the impact of $713 million of non-cash charges at Transco and Northwest Pipeline primarily related to regulatory liabilities established as a result of the recently enacted Tax Cuts and Jobs Act of 2017 ("Tax Reform Act"). Some of the rates charged to customers of our regulated natural gas pipelines are subject to periodic FERC rate case filings, which permit the recovery of an income tax allowance that includes a deferred income tax component in our recourse rates. As a result of the reduced income tax rate from the Tax Reform Act and the resulting regulatory liabilities, we expect that any future rate case settlements or proceedings before the FERC will be impacted by this lower income tax allowance. However, the actual amount and timing of any return of this regulatory liability to customers will be subject to negotiations in future rate proceedings. We expect that the amortization of the regulatory liability will be over an extended period of time (as much as 20 years or more). Considering all of these recourse rate-making elements, Transco still expects to file for increased cost-of-service rates in its upcoming initial rate filing in 2018. Fourth-quarter 2017 results were positively impacted by the absence of an impairment on equity method investments in fourth-quarter 2016.

For the year, Williams Partners reported unaudited net income attributable to controlling interests of $871 million, a $440 million improvement compared to full-year 2016 results. The favorable change was driven primarily by gains on the sale of assets, the absence of impairments of equity-method investments, and higher revenues for the Atlantic-Gulf segment. Partially offsetting the increases was the impact of the non-cash charges related to the Tax Reform Act as described in the previous paragraph, a net increase in impairments of certain assets, and the absence of results associated with the Geismar olefins facility, which was sold July 6, 2017.

Williams Partners reported fourth-quarter 2017 Adjusted EBITDA of $1.150 billion, a $37 million increase over fourth-quarter 2016. Williams Partners' current businesses increased Adjusted EBITDA by $84 million in fourth-quarter 2017 vs. fourth-quarter 2016, driven by $117 million increased fee-based revenues, due primarily to the growth in fee-based revenues in the Atlantic-Gulf and West segments partially offset by $30 million in higher operating and maintenance (O&M) expenses. The $84 million improvement from the current businesses was partially offset by the absence of $47 million Adjusted EBITDA earned in fourth-quarter 2016 from the NGL & Petchem Services segment primarily as a result of the sale of the Geismar olefins facility on July 6, 2017.

For the year, Williams Partners reported Adjusted EBITDA of $4.472 billion, a $45 million increase over full-year 2016 results. Williams Partners' current businesses increased Adjusted EBITDA by $202 million in 2017 compared to 2016. The improvement was due primarily to a $147 million increase in fee-based revenues driven primarily from new assets brought online by the Atlantic-Gulf segment. The partnership's full-year 2017 results also benefited from $51 million increased commodity margins and $28 million higher EBITDA from joint ventures, partially offset by $63 million higher O&M expenses. The $202 million improvement from the current businesses was partially offset by the absence of $157 million Adjusted EBITDA earned in 2016 from the NGL & Petchem Services segment primarily as a result of the sale of the Geismar olefins facility on July 6, 2017.

Distributable Cash Flow and Distributions

For fourth-quarter 2017, Williams Partners generated $702 million in distributable cash flow (DCF) attributable to partnership operations, compared with $699 million in DCF attributable to partnership operations for fourth-quarter 2016. DCF was favorably impacted by the partnership's change in Adjusted EBITDA and a $31 million decrease in interest expense. DCF for fourth-quarter 2017 was reduced by $58 million for the removal of deferred revenue amortization associated with the fourth-quarter 2016 contract restructurings and prepayments in the Barnett Shale and Mid-Continent region. For fourth-quarter 2017, the cash distribution coverage ratio was 1.22x.

For the year, Williams Partners generated $2.821 billion in DCF attributable to partnership operations, an unfavorable change of $149 million compared with full-year 2016 DCF results. For 2017, DCF was reduced by $233 million for the deferred revenue amortization associated with the previously described contract restructurings and prepayments. Also impacting DCF for full-year 2017 was $42 million increased maintenance capital expenditures. Partially offsetting these unfavorable changes were a $114 million decrease in interest expense and a $45 million improvement in Adjusted EBITDA. As described above, the partnership's Adjusted EBITDA from current businesses increased $202 million, but was partially offset by $157 million lower Adjusted EBITDA from assets sold. For full-year 2017, the cash distribution coverage was 1.23x. Both DCF and coverage exceeded the midpoint of financial guidance provided in January 2017.

Williams Partners recently announced a regular quarterly cash distribution of $0.60 per unit, payable Feb. 9, 2018, to its common unitholders of record at the close of business on Feb. 2, 2018.

CEO Perspective

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

"I am pleased with the organization's strong execution in 2017. Our organization has been working hard to keep its promises to our customers, shareholders, and other stakeholders with timely and safe delivery of our projects, including Transco’s ‘Big 5’ projects (Gulf Trace, Hillabee Phase 1, Dalton, New York Bay and Virginia Southside II). This is reflected in our financial results where we exceeded the midpoint of our guidance range for Adjusted EBITDA, DCF and Cash Coverage ratios.

"We achieved these impressive results, which include improvement in year-over-year Adjusted EBITDA for both fourth-quarter and full-year 2017, in spite of the impact of multiple hurricanes and more than $3 billion in asset sales since September 2016. Our stable foundation of demand-driven expansions continues to grow our business. In 2018, we look forward to a full year of revenue from our ‘Big 5’ as well as contributions from our Atlantic Sunrise project later this year and the associated growth in Northeast gathering volumes.

"We also carried out our financial repositioning in January of 2017 in a way that positioned the company to fund an attractive slate of large-scale expansion projects without accessing public equity markets, strengthened distribution coverage, enhanced our credit profile, improved our cost of capital and underpinned our growth outlook. As a result of a full year of executing on the key aspects of our plan, we reduced WPZ Net Debt for the year by 15 percent and also dramatically reduced our commodity exposure.

"As the Atlantic Sunrise project construction continues, the debottlenecking of the Northeast is starting to occur as other pipelines in the Northeast have also been placed in service recently or will be brought online in the near future. We are beginning to see some of the key fundamentals of our strategy take shape in the Northeast where we have a leading market share and a path to deliver long-term sustainable shareholder value. Volumes are increasing and our focus on executing the company’s natural gas-focused business strategy is producing predictable fee-based revenue growth backed by long-term commitments."

Business Segment Results

For full-year 2017 results, Williams Partners' operations are comprised of the following reportable segments: Atlantic-Gulf, West, Northeast G&P, and NGL & Petchem Services. As of July 7, 2017, following the completed sale of Williams Partners' ownership interest in the Geismar olefins plant on July 6, 2017, the partnership's NGL & Petchem Services segment no longer contained any operating assets.

Amounts in millions			4Q 2017											4Q 2016											YTD 2017												YTD 2016
			Modified							Adjusted				Modified								Adjusted			Modified								Adjusted				Modified							Adjusted
			EBITDA				Adjust.			EBITDA				EBITDA				Adjust.				EBITDA			EBITDA				Adjust.				EBITDA				EBITDA				Adjust.			EBITDA
Atlantic-Gulf			($96	)			$529			$433				$456				($2	)			$454			$1,238				$541				$1,779				$1,621				$40			$1,661
West			286				195			481				542				(148	)			394			412				1,256				1,668				1,544				107			1,651
Northeast G&P			231				7			238				197				22				219			819				140				959				853				33			886
NGL & Petchem Services			(4	)			3			(1	)			49				(3	)			46			1,161				(1,089	)			72				(145	)			374			229
Other			(9	)			8			(1	)			(9	)			9				—			(14	)			8				(6	)			(9	)			9			—
Total			$408				$742			$1,150				$1,235				($122	)			$1,113			$3,616				$856				$4,472				$3,864				$563			$4,427
Williams Partners uses Modified EBITDA for its segment reporting. Definitions of Modified EBITDA and Adjusted EBITDA and schedules reconciling these measures to net income are included in this news release.

Atlantic-Gulf

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

The Atlantic-Gulf segment reported Modified EBITDA of ($96) million for fourth-quarter 2017, compared with $456 million for fourth-quarter 2016. Adjusted EBITDA decreased by $21 million to $433 million for the same time period. The unfavorable change in Modified EBITDA was due primarily to the impact of $493 million of non-cash charges at Transco primarily related to regulatory liabilities resulting from the Tax Reform Act and previously described in this news release. The Tax Reform Act also led to non-cash charges of $11 million of proportional Modified EBITDA of joint-ventures from Transco's investments. The non-cash charges associated with the Tax Reform Act did not impact 2017 Adjusted EBITDA. The segment benefited from a $57 million increase in fee-based revenues from Transco expansion projects brought online. Partially offsetting the improvement were $32 million increased O&M expenses primarily associated with Transco's integrity and pipeline maintenance programs and $20 million decreased proportional EBITDA from the partnership's Discovery joint venture, due to a significant decline in volumes from the Hadrian field. Results for fourth-quarter 2017 also reflect the absence of $22 million in fee-based revenues and commodity margins from volumes transported and processed by Williams Partners on a short-term basis due to an unplanned outage on another company's system in 2016.

For the year, Atlantic-Gulf reported Modified EBITDA of $1.238 billion, a decrease of $383 million from full-year 2016. Adjusted EBITDA increased $118 million to $1.779 billion. The unfavorable change in Modified EBITDA was due primarily to the impact of the non-cash charges associated with the Tax Reform Act referenced in the previous paragraph. Adjusted EBITDA benefited from $132 million increased fee-based revenues primarily from Transco expansion projects brought online, and a $104 million improvement from Gulfstar One. Partially offsetting the increases were $90 million higher O&M expenses primarily associated with Transco's integrity and pipeline maintenance programs. Results for full-year 2017 also reflect the absence of $42 million in fee-based revenues and commodity margins from volumes transported and processed by Williams Partners on a short-term basis due to an unplanned outage on another company's system in 2016.

West

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

The West segment reported Modified EBITDA of $286 million for fourth-quarter 2017, compared with $542 million for fourth-quarter 2016. Adjusted EBITDA increased by $87 million to $481 million. The unfavorable change in Modified EBITDA was due primarily to the impact of $220 million of non-cash charges at Northwest Pipeline primarily related to regulatory liabilities resulting from the Tax Reform Act and previously described in this press release. Adjusted EBITDA, which is not impacted by the non-cash charges associated with the Tax Reform Act, benefited from $54 million higher fee-based revenues due to increased volumes primarily in the Haynesville, other rate changes, and a $24 million positive impact from the 2016 Barnett contract restructuring and prepayment. The year-over-year comparison for the quarter also benefited from $16 million improved commodity margins and $20 million in lower O&M and selling, general and administrative (SG&A) expenses. Partially offsetting these improvements was $10 million decreased proportional EBITDA from joint ventures, due in part to the partnership's sale of its interests in certain non-operated Delaware Basin assets in first-quarter 2017.

For the year, the West segment reported Modified EBITDA of $412 million, a decrease of $1.132 billion from full-year 2016 results. Adjusted EBITDA increased by $17 million to $1.668 billion. The unfavorable change in Modified EBITDA is due primarily to a $1.019 billion impairment of certain gathering operations in the Mid-Continent region and the non-cash charges associated with the Tax Reform Act described in the previous paragraph. Adjusted EBITDA excludes the impairment charge and is not impacted by the non-cash charges associated with the Tax Reform Act. The favorable change in Adjusted EBITDA reflects $73 million lower O&M and SG&A expenses and $54 million improved commodity margins. Revenues were also impacted by lower rates associated with 2016 contract restructurings and lower volumes driven by natural declines, partially offset by the amortization of deferred revenue from those 2016 contract restructurings and prepayments. As a result, Adjusted EBITDA reflects $87 million of lower fee-based revenues. When compared to full-year 2016 results, the segment was also negatively impacted by $31 million in decreased proportional EBITDA of joint ventures, due in part to the partnership’s sale of its interests in certain non-operated Delaware Basin assets in first-quarter 2017.

Northeast G&P

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

The Northeast G&P segment reported Modified EBITDA of $231 million for fourth-quarter 2017, compared with $197 million for fourth-quarter 2016. Adjusted EBITDA increased by $19 million to $238 million. The current year benefited from a $25 million increase in proportional EBITDA of joint ventures due largely to the partnership's increase in ownership in two Marcellus shale gathering systems in first-quarter 2017. Fee-based revenues were stable between the two periods due to increases in the Susquehanna and Ohio River systems that offset decreases in the Utica.

For the year, the Northeast G&P segment reported Modified EBITDA of $819 million, a decrease of $34 million compared with full-year 2016 results. Adjusted EBITDA increased by $73 million to $959 million. The unfavorable change in Modified EBITDA reflected a $115 million impairment of certain gathering operations in the Marcellus South. The impairment charge is excluded from Adjusted EBITDA, which benefited from a $71 million increase in proportional EBITDA of joint ventures due largely to the partnership's increase in ownership in two Marcellus shale gathering systems in first-quarter 2017. Fee-based revenues were stable between the two periods due to increases in the Susquehanna and Ohio River systems that offset decreases in the Utica.

NGL & Petchem Services

On Jan. 1, 2017, this segment included the partnership’s 88.46 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter. On July 6, 2017, the partnership announced that it had completed the sale of all of its membership interest in the Geismar olefins production facility and associated complex. On June 30, 2017 the partnership completed the sale of the refinery grade propylene splitter. Prior to September 2016, this reporting segment also included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility, which were subsequently sold. As of July 7, 2017, this segment no longer contained any operating assets.

For the year, the NGL & Petchem Services segment reported Modified EBITDA of $1.161 billion, an improvement of $1.306 billion compared with full-year 2016 results. Adjusted EBITDA decreased $157 million to $72 million. The improvement in Modified EBITDA was driven primarily by the $1.095 billion gain resulting from the sale of the partnership's interest in the Geismar olefins facility on July 6, 2017, and the absence of a $341 million impairment of our former Canadian operations in 2016. These items are excluded from Adjusted EBITDA. The current year was also impacted by the absence of EBITDA associated with the previously described assets that were sold by the partnership.

Notable Accomplishments

On Dec. 5, 2017, the partnership announced that it had successfully placed into service its Virginia Southside II expansion project, the fifth of Transco’s “Big 5” expansions to be placed into service in 2017. These five, fully-contracted expansion projects (Gulf Trace, Hillabee Phase 1, Dalton, New York Bay and Virginia Southside II) combined to add more than 2.8 million dekatherms per day (Dth/d) of firm transportation capacity to the Transco pipeline system in 2017, contributing to the increase of Transco’s design capacity by approximately 25 percent.

Williams Partners' Credit Profile Update

The partnership continued to maintain its strengthened balance sheet and credit profile with nearly $2.1 billion of Total Debt reduction and more than $700 million increase in cash, year-to-date, resulting in a $2.8 billion reduction in Net Debt (long-term debt plus commercial paper less cash). As of the end of fourth-quarter 2017, the partnership had Total Debt of $16.5 billion and cash and cash equivalents of $881 million, which the partnership intends to use to fund growth capital expenditures and long-term investments.

2018 Guidance

Current guidance for 2018 is set out in the following table. As noted in the table below, Williams Partners' Adjusted EBITDA and Distributable Cash Flow estimates for 2018 have recently been impacted by non-cash adjustments related to the new GAAP revenue recognition standard and Tax Reform Act. For Williams Partners' Adjusted EBITDA, the unfavorable non-cash impacts of these two items were approximately $120 million for the new GAAP revenue recognition standard and approximately $30 million for tax reform primarily due to Northwest Pipeline even though rates on Northwest Pipeline remain unchanged until the next rate case cycle expected to occur in 2021.

The main effect of the new GAAP revenue recognition standard was to extend the amortization of deferred revenue associated with certain 2016 contract restructurings and pre-payments by approximately 10 years resulting in lower 2018 and 2019 revenue and then higher revenue amounts through 2029. Furthermore, as a result of the extended revenue amortization period under the new GAAP revenue standard, we have prospectively discontinued the adjustment which removed the DCF associated with these 2016 contract restructuring prepayments. Consequently, DCF is expected to be approximately $140 million higher in 2018 than it otherwise would have been absent this prospective change.

Amounts in billions, except per-unit cash distribution, cash dividend and coverage ratio amounts. All income amounts attributable to Williams Partners LP.
Williams Partners			2018
Net income (1)			$1.5-$1.7
Adjusted EBITDA (1)(2)(3)			$4.45-$4.65
Distributable Cash Flow (1)(2)(4)			$2.9-$3.2
Cash Distribution Coverage Ratio (1)(2)(4)			~1.2x (midpoint of guidance)
Distribution Growth Rate (3) (Quarterly Distribution Increases)			5-7% annual growth for 2018 and 2019
Total Growth Capital Expenditures			$2.7
Transco Growth Capital Expenditures			$1.7
Leverage (5)			< 4.5x

(1)		Assumes 2018 WTI oil price of approximately $59.00 per barrel and Henry Hub natural gas price of approximately $2.80 per mmbtu.
(2)		For Williams Partners, Adjusted EBITDA, Distributable Cash Flow and Cash Distribution Coverage Ratio are non-GAAP measures and for Williams, Dividend Coverage Ratio is a non-GAAP measure; reconciliations to the most relevant measures are attached to this news release.
(3)		Includes $0.15 billion unfavorable effects of new revenue recognition standard and tax reform. Guidance would be $4.6-$4.8 without these items. See description above.
(4)		Includes $0.14 billion favorable effects associated with changes in the treatment of certain 2016 contract restructurings. Guidance would be $2.8-$3.1 without these items. See description above.
(5)		Estimated rating agency adjusted Debt to EBITDA

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

Williams Partners’ fourth-quarter and full-year 2017 financial results package will be posted shortly at www.williams.com.

Williams Partners and Williams will host a joint Q&A live webcast on Thursday, Feb. 15 at 9:30 a.m. Eastern Time (8:30 a.m. Central Time). A limited number of phone lines will be available at (888) 468-2440. International callers should dial (719) 325-4790. The conference ID is 2010872. The link to the webcast, as well as replays of the webcast, will be available for at least 90 days following the event at www.williams.com.

Form 10-K

The partnership plans to file its 2017 Form 10-K with the Securities and Exchange Commission (SEC) 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 and accompanying materials may include certain financial measures – Adjusted EBITDA, distributable cash flow and cash distribution coverage ratio – that are non-GAAP financial measures as defined under the rules of the SEC.

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

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

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

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

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

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

About Williams Partners

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

Forward-Looking Statements

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

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

• Levels of cash distributions with respect to limited partner interests;
• Our and our affiliates’ future credit ratings;
• Amounts and nature of future capital expenditures;
• Expansion and growth of our business and operations;
• Expected in-service dates for capital projects;
• Financial condition and liquidity;
• Business strategy;
• Cash flow from operations or results of operations;
• Seasonality of certain business components;
• Natural gas and natural gas liquids prices, supply, and demand;
• Demand for our services.

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

• Whether we will produce sufficient cash flows to provide expected levels of cash distributions;
• Whether we elect to pay expected levels of cash distributions;
• Whether we will be able to effectively execute our financing plan;
• Whether Williams will be able to effectively manage the transition in its board of directors and management as well as successfully execute its business restructuring;
• Availability of supplies, including lower than anticipated volumes from third parties served by our business, and market demand;
• Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins;
• Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);
• The strength and financial resources of our competitors and the effects of competition;
• Whether we are able to successfully identify, evaluate, and timely execute our capital projects and other investment opportunities in accordance with our forecasted capital expenditures budget;
• Our ability to successfully expand our facilities and operations;
• Development and rate of adoption of alternative energy sources;
• The impact of operational and developmental hazards, unforeseen interruptions, and the availability of adequate insurance coverage;
• The impact of existing and future laws (including but not limited to the Tax Cuts and Jobs Act of 2017), regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;
• Our costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;
• Changes in maintenance and construction costs;
• Changes in the current geopolitical situation;
• Our exposure to the credit risk of our customers and counterparties;
• Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally-recognized credit rating agencies and the availability and cost of capital;
• The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;
• Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;
• Acts of terrorism, including cybersecurity threats, and related disruptions;
• Additional risks described in our filings with the Securities and Exchange Commission (SEC).

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

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

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

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

Williams Partners L.P.
Reconciliation of Non-GAAP Measures
(UNAUDITED)
			2016																									2017
(Dollars in millions, except coverage ratios)			1st Qtr					2nd Qtr					3rd Qtr					4th Qtr					Year					1st Qtr					2nd Qtr					3rd Qtr					4th Qtr					Year
Williams Partners L.P.
Reconciliation of "Net Income (Loss)" to "Modified EBITDA", Non-GAAP "Adjusted EBITDA" and "Distributable cash flow"
Net income (loss)			$	79				$	(77	)			$	351				$	166				$	519				$	660				$	348				$	284				$	(317	)			$	975
Provision (benefit) for income taxes				1					(80	)				(6	)				5					(80	)				3					1					(1	)				3					6
Interest expense				229					231					229					227					916					214					205					202					201					822
Equity (earnings) losses				(97	)				(101	)				(104	)				(95	)				(397	)				(107	)				(125	)				(115	)				(87	)				(434	)
Impairment of equity-method investments				112					—					—					318					430					—					—					—					—					—
Other investing (income) loss - net				—					(1	)				(28	)				—					(29	)				(271	)				(2	)				(4	)				(4	)				(281	)
Proportional Modified EBITDA of equity-method investments				189					191					194					180					754					194					215					202					184					795
Depreciation and amortization expenses				435					432					426					427					1,720					433					423					424					420					1,700
Accretion expense associated with asset retirement obligations for nonregulated operations				7					9					8					7					31					6					11					8					8					33
Modified EBITDA				955					604					1,070					1,235					3,864					1,132					1,076					1,000					408					3,616
Adjustments
Estimated minimum volume commitments				60					64					70					(194	)				—					15					15					18					(48	)				—
Severance and related costs				25					—					—					12					37					9					4					5					4					22
Potential rate refunds associated with rate case litigation				15					—					—					—					15					—					—					—					—					—
Settlement charge from pension early payout program				—					—					—					—					—					—					—					—					35					35
Regulatory charges resulting from Tax Reform				—					—					—					—					—					—					—					—					713					713
Share of regulatory charges resulting from Tax Reform for equity-method investments				—					—					—					—					—					—					—					—					11					11
ACMP Merger and transition costs				5					—					—					—					5					—					4					3					4					11
Constitution Pipeline project development costs				—					8					11					9					28					2					6					4					4					16
Share of impairment at equity-method investment				—					—					6					19					25					—					—					1					—					1
Geismar Incident adjustment				—					—					—					(7	)				(7	)				(9	)				2					8					(1	)				—
Gain on sale of Geismar Interest				—					—					—					—					—					—					—					(1,095	)				—					(1,095	)
Impairment of certain assets				—					389					—					22					411					—					—					1,142					9					1,151
Ad valorem obligation timing adjustment				—					—					—					—					—					—					—					7					—					7
Organizational realignment-related costs				—					—					—					24					24					4					6					6					2					18
Loss related to Canada disposition				—					—					32					2					34					(3	)				(1	)				4					4					4
Gain on asset retirement				—					—					—					(11	)				(11	)				—					—					(5	)				5					—
Gains from contract settlements and terminations				—					—					—					—					—					(13	)				(2	)				—					—					(15	)
Accrual for loss contingency				—					—					—					—					—					9					—					—					—					9
Gain on early retirement of debt				—					—					—					—					—					(30	)				—					3					—					(27	)
Gain on sale of RGP Splitter				—					—					—					—					—					—					(12	)				—					—					(12	)
Expenses associated with Financial Repositioning				—					—					—					—					—					—					2					—					—					2
Expenses associated with strategic asset monetizations				—					—					—					2					2					1					4					—					—					5
Total EBITDA adjustments				105					461					119					(122	)				563					(15	)				28					101					742					856
Adjusted EBITDA				1,060					1,065					1,189					1,113					4,427					1,117					1,104					1,101					1,150					4,472
Maintenance capital expenditures (1)				(58	)				(75	)				(121	)				(147	)				(401	)				(53	)				(100	)				(136	)				(154	)				(443	)
Interest expense (cash portion) (2)				(241	)				(245	)				(244	)				(239	)				(969	)				(224	)				(216	)				(207	)				(208	)				(855	)
Cash taxes				—					—					—					(3	)				(3	)				(5	)				(1	)				(4	)				(2	)				(12	)
Income attributable to noncontrolling interests (3)				(29	)				(13	)				(31	)				(27	)				(100	)				(27	)				(32	)				(27	)				(27	)				(113	)
WPZ restricted stock unit non-cash compensation				7					5					2					2					16					2					1					1					1					5
Amortization of deferred revenue associated with certain 2016 contract restructurings				—					—					—					—					—					(58	)				(58	)				(59	)				(58	)				(233	)
Distributable cash flow attributable to Partnership Operations (4)				739					737					795					699					2,970					752					698					669					702					2,821
Total cash distributed (5)			$	725				$	725				$	734				$	762				$	2,946				$	567				$	574				$	574				$	574				$	2,289
Coverage ratios:
Distributable cash flow attributable to partnership operations divided by Total cash distributed				1.02					1.02					1.08					0.92					1.01					1.33					1.22					1.17					1.22					1.23
Net income (loss) divided by Total cash distributed				0.11					(0.11	)				0.48					0.22					0.18					1.16					0.61					0.49					(0.55	)				0.43

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

Williams Partners L.P.
Reconciliation of “Modified EBITDA” to Non-GAAP “Adjusted EBITDA”
(UNAUDITED)
			2016																							2017
(Dollars in millions)			1st Qtr				2nd Qtr					3rd Qtr				4th Qtr					Year					1st Qtr					2nd Qtr					3rd Qtr					4th Qtr					Year
Modified EBITDA:
Northeast G&P			$	220			$	222				$	214			$	197				$	853				$	226				$	247				$	115				$	231				$	819
Atlantic-Gulf				382				360					423				456					1,621					450					454					430					(96	)				1,238
West				327				312					363				542					1,544					385					356					(615	)				286					412
NGL & Petchem Services				26				(290	)				70				49					(145	)				51					30					1,084					(4	)				1,161
Other				—				—					—				(9	)				(9	)				20					(11	)				(14	)				(9	)				(14	)
Total Modified EBITDA			$	955			$	604				$	1,070			$	1,235				$	3,864				$	1,132				$	1,076				$	1,000				$	408				$	3,616
Adjustments:
Northeast G&P
Severance and related costs			$	3			$	—				$	—			$	—				$	3				$	—				$	—				$	—					—				$	—
Share of impairment at equity-method investments				—				—					6				19					25					—					—					1					—					1
ACMP Merger and transition costs				2				—					—				—					2					—					—					—					—					—
Impairment of certain assets				—				—					—				—					—					—					—					121					—					121
Ad valorem obligation timing adjustment				—				—					—				—					—					—					—					7					—					7
Settlement charge from pension early payout program				—				—					—				—					—					—					—					—					7					7
Organizational realignment-related costs				—				—					—				3					3					1					1					2					—					4
Total Northeast G&P adjustments				5				—					6				22					33					1					1					131					7					140
Atlantic-Gulf
Potential rate refunds associated with rate case litigation				15				—					—				—					15					—					—					—					—					—
Severance and related costs				8				—					—				—					8					—					—					—					—					—
Constitution Pipeline project development costs				—				8					11				9					28					2					6					4					4					16
Settlement charge from pension early payout program				—				—					—				—					—					—					—					—					15					15
Regulatory charges resulting from Tax Reform				—				—					—				—					—																				493					493
Share of regulatory charges resulting from Tax Reform for equity-method investments				—				—					—				—					—					—					—					—					11					11
Organizational realignment-related costs				—				—					—				—					—					1					2					2					1					6
Gain on asset retirement				—				—					—				(11	)				(11	)				—					—					(5	)				5					—
Total Atlantic-Gulf adjustments				23				8					11				(2	)				40					3					8					1					529					541
West
Estimated minimum volume commitments				60				64					70				(194	)				—					15					15					18					(48	)				—
Severance and related costs				10				—					—				3					13					—					—					—					—					—
ACMP Merger and transition costs				3				—					—				—					3					—					—					—					—					—
Impairment of certain assets				—				48					—				22					70					—					—					1,021					9					1,030
Settlement charge from pension early payout program				—				—					—				—					—					—					—					—					13					13
Regulatory charge associated with Tax Reform				—				—					—				—					—					—					—					—					220					220
Organizational realignment-related costs				—				—					—				21					21					2					3					2					1					8
Gains from contract settlements and terminations				—				—					—				—					—					(13	)				(2	)				—					—					(15	)
Total West adjustments				73				112					70				(148	)				107					4					16					1,041					195					1,256
NGL & Petchem Services
Impairment of certain assets				—				341					—				—					341					—					—					—					—					—
Loss related to Canada disposition				—				—					32				2					34					(3	)				(1	)				4					4					4
Severance and related costs				4				—					—				—					4					—					—					—					—					—
Expenses associated with strategic asset monetizations				—				—					—				2					2					1					4					—					—					5
Geismar Incident adjustments				—				—					—				(7	)				(7	)				(9	)				2					8					(1	)				—
Gain on sale of Geismar Interest				—				—					—				—					—					—					—					(1,095	)				—					(1,095	)
Gain on sale of RGP Splitter				—				—					—				—					—					—					(12	)									—					(12	)
Accrual for loss contingency				—				—					—				—					—					9					—					—					—					9
Total NGL & Petchem Services adjustments				4				341					32				(3	)				374					(2	)				(7	)				(1,083	)				3					(1,089	)
Other
Severance and related costs				—				—					—				9					9					9					4					5					4					22
ACMP Merger and transition costs				—				—					—				—					—					—					4					3					4					11
Expenses associated with Financial Repositioning				—				—					—				—					—					—					2					—					—					2
Gain on early retirement of debt				—				—					—				—					—					(30	)				—					3					—					(27	)
Total Other adjustments				—				—					—				9					9					(21	)				10					11					8					8
Total Adjustments			$	105			$	461				$	119			$	(122	)			$	563				$	(15	)			$	28				$	101				$	742				$	856
Adjusted EBITDA:
Northeast G&P			$	225			$	222				$	220			$	219				$	886				$	227				$	248				$	246				$	238				$	959
Atlantic-Gulf				405				368					434				454					1,661					453					462					431					433					1,779
West				400				424					433				394					1,651					389					372					426					481					1,668
NGL & Petchem Services				30				51					102				46					229					49					23					1					(1	)				72
Other				—				—					—				—					—					(1	)				(1	)				(3	)				(1	)				(6	)
Total Adjusted EBITDA			$	1,060			$	1,065				$	1,189			$	1,113				$	4,427				$	1,117				$	1,104				$	1,101				$	1,150				$	4,472

WPZ Reconciliation of "Net Income (Loss)" to "Modified EBITDA",
Non-GAAP "Adjusted EBITDA" and "Distributable Cash Flow"
			2018 Guidance Range
(Dollars in billions, except coverage ratios)			Low					Mid					High
Net income (loss)			$	1.500				$	1.600				$	1.700
Provision (benefit) for income taxes									—
Interest expense									0.825
Equity (earnings) losses									(0.325	)
Proportional Modified EBITDA of equity-method investments									0.700
Depreciation and amortization expenses and accretion for asset retirement obligations associated with nonregulated operations									1.750
Modified EBITDA				4.450					4.550					4.650
Total EBITDA adjustments									—
Adjusted EBITDA				4.450					4.550					4.650
Maintenance capital expenditures (1)				(0.550	)				(0.500	)				(0.450	)
Interest expense (cash portion) (2)									(0.875	)
Income attributable to noncontrolling interests, cash taxes and other									(0.125	)
Distributable cash flow attributable to Partnership Operations			$	2.900				$	3.050				$	3.200
Total cash distributed			$	2.450				$	2.450				$	2.450
Cash Coverage Ratio (Distributable cash flow attributable to Partnership Operations / Total cash distributed)			1.18x					1.24x					1.31x
(1) Includes proportionate share of maintenance capital expenditures of equity investments.
(2) Includes proportionate share of interest expense of equity investments.

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