Williams Partners Reports Third-Quarter 2017 Financial Results

  • 3Q 2017 Net Income of $259 Million
  • 3Q 2017 Adjusted EBITDA of $1.101 Billion
  • 3Q 2017 Cash Distribution Coverage Ratio of 1.17x; 1.24x Year-to-Date
  • Placed 4 Transco Expansions (Gulf Trace, Hillabee Phase 1, Dalton Expansion, and New York Bay Expansion) Into Service to Date in 2017; Design Capacity Up 25%
  • Williams Partners Continues to Significantly Improve Credit Profile; Net Debt (Long-term Debt Less Cash) Reduced by $3 Billion Since Jan. 1, 2017
  • Achieved Key Milestones for Atlantic Sunrise Project
Wednesday, November 1, 2017 4:15 pm EDT

Dateline:

TULSA, Okla.

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

     
Summary Financial Information 3Q YTD
Amounts in millions, except per-unit amounts. Per unit amounts are reported on a diluted basis. All amounts are attributable to Williams Partners L.P. 2017   2016 2017     2016
     
GAAP Measures
Cash Flow from Operations $ 596 $ 685 $ 2,103 $ 2,351
Net income (loss) $ 259 $ 326 $ 1,213 $ 286
Net income (loss) per common unit $ 0.27 $ 0.42 $ 1.26 ($0.32 )
 
Non-GAAP Measures (1)
Adjusted EBITDA $ 1,101 $ 1,189 $ 3,322 $ 3,314
DCF attributable to partnership operations $ 669 $ 795 $ 2,119 $ 2,271
Cash distribution coverage ratio 1.17 x 1.08 x 1.24 x 1.04 x
 

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

 

Third-Quarter 2017 Financial Results

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

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

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

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

Distributable Cash Flow and Distributions

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

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

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

CEO Perspective

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

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

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

“Our existing asset footprint and the efficient incremental expansions available to us have also been highlighted in our Northeast G&P and West segments. Our recently announced agreement to expand our services in the Northeast for our valued customer, Southwestern Energy, showcases how well-positioned our Northeast G&P segment is to serve the growing gas production in the Marcellus and Utica. We are also positioned to capture growth in the Haynesville where in August, we completed the Springridge South plant expansion, and in Wyoming where we are able to bring more volumes onto our Wamsutter system after placing our Chain Lake compressor station into service in October to meet the growing demand of a customer.

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

Business Segment Results

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

Amounts in millions   3Q 2017     3Q 2016     YTD 2017     YTD 2016

Modified
EBITDA

  Adjust.  

Adjusted
EBITDA

Modified
EBITDA
  Adjust.   Adjusted

EBITDA

Modified

EBITDA

  Adjust.   Adjusted

EBITDA

Modified

EBITDA

  Adjust.   Adjusted

EBITDA

Atlantic -Gulf $ 430   $ 1   $ 431 $ 423   $ 11   $ 434 $ 1,334   $ 12   $ 1,346 $ 1,165   $ 42   $ 1,207
West (615 ) 1,041 426 363 70 433 126 1,061 1,187 1,002 255 1,257
Northeast G&P 115 131 246 214 6 220 588 133 721 656 11 667
NGL & Petchem Services 1,084 (1,083 ) 1 70 32 102 1,165 (1,092 ) 73 (194 ) 377 183
Other   (14 )     11       (3 )             (5 )           (5 )            
Total $ 1,000     $ 101     $ 1,101   $ 1,070   $ 119   $ 1,189 $ 3,208     $ 114     $ 3,322   $ 2,629     $ 685   $ 3,314
 
Definitions of modified EBITDA and adjusted EBITDA and schedules reconciling these measures to net income are included in this news release.
 

Atlantic-Gulf

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

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

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

West

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

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

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

Northeast G&P

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

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

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

NGL & Petchem Services

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

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

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

Atlantic Sunrise Update

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

Additional Notable Recent Accomplishments

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

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

Williams Partners' Credit Profile Improvement including Debt Reduction Update

The partnership continued to strengthen its balance sheet and credit profile during the quarter with nearly $2.1 billion of debt reduction. As of the end of third-quarter 2017, the partnership had total debt of $16.5 billion. Year-to-date, cash and cash equivalents increased by $1.02 billion to $1.17 billion, which the partnership intends to use primarily to fund growth capital expenditures and long-term investments.

Guidance

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

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

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

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

Form 10-Q

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

Definitions of Non-GAAP Measures

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

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

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

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

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

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

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

About Williams Partners

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

Forward-Looking Statements

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

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

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

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

  • Whether we will produce sufficient cash flows to provide expected levels of cash distributions;
  • Whether we elect to pay expected levels of cash distributions;
  • Whether we will be able to effectively execute our financing plan;
  • Whether Williams will be able to effectively manage the transition in its board of directors and management as well as successfully execute its business restructuring;
  • Availability of supplies, including lower than anticipated volumes from third parties served by our business, and market demand;
  • Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins;
  • Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);
  • The strength and financial resources of our competitors and the effects of competition;
  • Whether we are able to successfully identify, evaluate, and timely execute our capital projects and other investment opportunities in accordance with our forecasted capital expenditures budget;
  • Our ability to successfully expand our facilities and operations;
  • Development and rate of adoption of alternative energy sources;
  • The impact of operational and developmental hazards, unforeseen interruptions, and the availability of adequate insurance coverage;
  • The impact of existing and future laws, regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;
  • Our costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;
  • Changes in maintenance and construction costs;
  • Changes in the current geopolitical situation;
  • Our exposure to the credit risk of our customers and counterparties;
  • Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally-recognized credit rating agencies and the availability and cost of capital;
  • The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;
  • Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;
  • Acts of terrorism, including cybersecurity threats, and related disruptions;
  • Additional risks described in our filings with the Securities and Exchange Commission (SEC).

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

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

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

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

 

 

Williams Partners L.P.

 
Non-GAAP Reconciliations,
Financial Highlights, and Operating Statistics
 
(UNAUDITED)
 
Final
 
September 30, 2017
   
Williams Partners L.P.
Reconciliation of Non-GAAP Measures

(UNAUDITED)

 
2016   2017  
(Dollars in millions, except coverage ratios)   1st Qtr   2nd Qtr   3rd Qtr   4th Qtr   Year 1st Qtr   2nd Qtr   3rd Qtr   Year
                                     
Williams Partners L.P.              
Reconciliation of "Net Income (Loss)" to "Modified EBITDA", Non-GAAP "Adjusted EBITDA" and "Distributable cash flow"
 
Net income (loss) $ 79 $   (77 ) $   351 $   166 $   519 $   660 $   348 $   284 $   1,292
Provision (benefit) for income taxes 1 (80 ) (6 ) 5 (80 ) 3 1 (1 ) 3
Interest expense 229 231 229 227 916 214 205 202 621
Equity (earnings) losses (97 ) (101 ) (104 ) (95 ) (397 ) (107 ) (125 ) (115 ) (347 )
Impairment of equity-method investments 112 318 430
Other investing (income) loss (1 ) (28 ) (29 ) (271 ) (2 ) (4 ) (277 )
Proportional Modified EBITDA of equity-method investments 189 191 194 180 754 194 215 202 611
Depreciation and amortization expenses 435 432 426 427 1,720 433 423 424 1,280
Accretion for asset retirement obligations associated with nonregulated operations   7     9     8     7     31   6     11     8     25  
Modified EBITDA 955 604 1,070 1,235 3,864 1,132 1,076 1,000 3,208
 
Adjustments
Estimated minimum volume commitments 60 64 70 (194 ) 15 15 18 48
Severance and related costs 25 12 37 9 4 5 18
Potential rate refunds associated with rate case litigation 15 15
ACMP Merger and transition costs 5 5 4 3 7
Constitution Pipeline project development costs 8 11 9 28 2 6 4 12
Share of impairment at equity-method investment 6 19 25 1 1
Geismar Incident adjustment (7 ) (7 ) (9 ) 2 8 1
Gain on sale of Geismar Interest (1,095 ) (1,095 )
Impairment of certain assets 389 22 411 1,142 1,142
Ad valorem obligation timing adjustment 7 7
Organizational realignment-related costs 24 24 4 6 6 16
Loss related to Canada disposition 32 2 34 (3 ) (1 ) 4
Gain on asset retirement (11 ) (11 ) (5 ) (5 )
Gains from contract settlements and terminations (13 ) (2 ) (15 )
Accrual for loss contingency 9 9
Gain on early retirement of debt (30 ) 3 (27 )
Gain on sale of RGP Splitter (12 ) (12 )
Expenses associated with Financial Repositioning 2 2
Expenses associated with strategic asset monetizations               2     2   1     4         5  
Total EBITDA adjustments   105     461     119     (122 )   563   (15 )   28     101     114  
Adjusted EBITDA 1,060 1,065 1,189 1,113 4,427 1,117 1,104 1,101 3,322
 
Maintenance capital expenditures (1) (58 ) (75 ) (121 ) (147 ) (401 ) (53 ) (100 ) (136 ) (289 )
Interest expense (cash portion) (2) (241 ) (245 ) (244 ) (239 ) (969 ) (224 ) (216 ) (207 ) (647 )
Cash taxes (3 ) (3 ) (5 ) (1 ) (4 ) (10 )
Income attributable to noncontrolling interests (3) (29 ) (13 ) (31 ) (27 ) (100 ) (27 ) (32 ) (27 ) (86 )
WPZ restricted stock unit non-cash compensation 7 5 2 2 16 2 1 1 4
Amortization of deferred revenue associated with certain 2016 contract restructurings                     (58 )   (58 )   (59 )   (175 )
 
Distributable cash flow attributable to Partnership Operations (4)   739     737     795     699     2,970   752     698     669     2,119  
 
Total cash distributed (5) $ 725 $ 725 $ 734 $ 762 $ 2,946 $ 567 $ 574 $ 574 $ 1,715
 
Coverage ratios:
Distributable cash flow attributable to partnership operations divided by Total cash distributed   1.02     1.02     1.08     0.92     1.01   1.33     1.22     1.17     1.24  
 
Net income (loss) divided by Total cash distributed   0.11     (0.11 )   0.48     0.22     0.18   1.16     0.61     0.49     0.75  
 
(1)   Includes proportionate share of maintenance capital expenditures of equity investments.
(2) Includes proportionate share of interest expense of equity investments.
(3) Excludes allocable share of certain EBITDA adjustments.
(4) The fourth quarter of 2016 includes income of $183 million associated with proceeds from the contract restructuring in the Barnett Shale and Mid-Continent region as the cash was received during 2016.
(5) In order to exclude the impact of the IDR waiver associated with the WPZ merger termination fee from the determination of coverage ratios, cash distributions have been increased by $10 million in the first quarter of 2016. Cash distributions for the third quarter of 2016 have been increased to exclude the impact of the $150 million IDR waiver associated with the sale of our Canadian operations. Cash distributions for the fourth quarter of 2016 and the first quarter of 2017 have been decreased by $50 million and $6 million, respectively, to reflect the amount paid by WMB to WPZ pursuant to the January 2017 Common Unit Purchase Agreement.
   
Williams Partners L.P.
Reconciliation of “Modified EBITDA” to Non-GAAP “Adjusted EBITDA”

(UNAUDITED)

 
2016   2017  
(Dollars in millions)   1st Qtr   2nd Qtr   3rd Qtr   4th Qtr   Year 1st Qtr   2nd Qtr   3rd Qtr   Year
                                     
Modified EBITDA:              
Northeast G&P $ 220 $ 222 $ 214 $ 197 $ 853 $ 226 $ 247 $ 115 $ 588
Atlantic-Gulf 382 360 423 456 1,621 450 454 430 1,334
West 327 312 363 542 1,544 385 356 (615 ) 126
NGL & Petchem Services 26 (290 ) 70 49 (145 ) 51 30 1,084 1,165
Other                 (9 )     (9 )   20       (11 )     (14 )     (5 )
Total Modified EBITDA $ 955   $ 604     $ 1,070   $ 1,235     $ 3,864   $ 1,132     $ 1,076     $ 1,000     $ 3,208  
 
Adjustments:

Northeast G&P

Severance and related costs $ 3 $ $ $ $ 3 $ $ $ $
Share of impairment at equity-method investments 6 19 25 1 1
ACMP Merger and transition costs 2 2
Impairment of certain assets 121 121
Ad valorem obligation timing adjustment 7 7
Organizational realignment-related costs                 3       3     1       1       2       4  
Total Northeast G&P adjustments 5 6 22 33 1 1 131 133

Atlantic-Gulf

Potential rate refunds associated with rate case litigation 15 15
Severance and related costs 8 8
Constitution Pipeline project development costs 8 11 9 28 2 6 4 12
Organizational realignment-related costs 1 2 2 5
Gain on asset retirement                 (11 )     (11 )               (5 )     (5 )
Total Atlantic-Gulf adjustments 23 8 11 (2 ) 40 3 8 1 12

West

Estimated minimum volume commitments 60 64 70 (194 ) 15 15 18 48
Severance and related costs 10 3 13
ACMP Merger and transition costs 3 3
Impairment of certain assets 48 22 70 1,021 1,021
Organizational realignment-related costs 21 21 2 3 2 7
Gains from contract settlements and terminations                           (13 )     (2 )           (15 )
Total West adjustments 73 112 70 (148 ) 107 4 16 1,041 1,061

NGL & Petchem Services

Impairment of certain assets 341 341
Loss related to Canada disposition 32 2 34 (3 ) (1 ) 4
Severance and related costs 4 4
Expenses associated with strategic asset monetizations 2 2 1 4 5
Geismar Incident adjustments (7 ) (7 ) (9 ) 2 8 1
Gain on sale of Geismar Interest (1,095 ) (1,095 )
Gain on sale of RGP Splitter (12 ) (12 )
Accrual for loss contingency                           9                   9  
Total NGL & Petchem Services adjustments 4 341 32 (3 ) 374 (2 ) (7 ) (1,083 ) (1,092 )

Other

Severance and related costs 9 9 9 4 5 18
ACMP Merger and transition costs 4 3 7
Expenses associated with Financial Repositioning 2 2
Gain on early retirement of debt                           (30 )           3       (27 )
Total Other adjustments 9 9 (21 ) 10 11
                               
Total Adjustments $ 105   $ 461     $ 119   $ (122 )   $ 563   $ (15 )   $ 28     $ 101     $ 114  
 
Adjusted EBITDA:
Northeast G&P $ 225 $ 222 $ 220 $ 219 $ 886 $ 227 $ 248 $ 246 $ 721
Atlantic-Gulf 405 368 434 454 1,661 453 462 431 1,346
West 400 424 433 394 1,651 389 372 426 1,187
NGL & Petchem Services 30 51 102 46 229 49 23 1 73
Other                           (1 )     (1 )     (3 )     (5 )
Total Adjusted EBITDA $ 1,060   $ 1,065     $ 1,189   $ 1,113     $ 4,427   $ 1,117     $ 1,104     $ 1,101     $ 3,322  
   
Williams Partners L.P.
Consolidated Statement of Income (Loss)

(UNAUDITED)

 
2016   2017  
(Dollars in millions, except per-unit amounts)   1st Qtr   2nd Qtr   3rd Qtr   4th Qtr   Year 1st Qtr   2nd Qtr   3rd Qtr   Year
                                     
Revenues:              
Service revenues $ 1,226 $ 1,210 $ 1,252 $ 1,485 $ 5,173 $ 1,256 $ 1,277 $ 1,304 $ 3,837
Product sales   428       530       655       705       2,318     727       642       581       1,950  
Total revenues 1,654 1,740 1,907 2,190 7,491 1,983 1,919 1,885 5,787
Costs and expenses:
Product costs 317 403 463 545 1,728 579 537 504 1,620
Operating and maintenance expenses 382 386 385 395 1,548 361 384 396 1,141
Depreciation and amortization expenses 435 432 426 427 1,720 433 423 424 1,280
Selling, general, and administrative expenses 181 139 147 163 630 156 154 140 450
Gain on sale of Geismar Interest (1,095 ) (1,095 )
Impairment of certain assets 6 396 1 54 457 1 2 1,142 1,145
Other (income) expense - net   24       24       59       4       111     3       7       22       32  
Total costs and expenses   1,345       1,780       1,481       1,588       6,194     1,533       1,507       1,533       4,573  
Operating income (loss)   309       (40 )     426       602       1,297     450       412       352       1,214  
Equity earnings (losses) 97 101 104 95 397 107 125 115 347
Impairment of equity-method investments (112 ) (318 ) (430 )
Other investing income (loss) - net 1 28 29 271 2 4 277
Interest incurred (240 ) (239 ) (236 ) (234 ) (949 ) (221 ) (214 ) (210 ) (645 )
Interest capitalized 11 8 7 7 33 7 9 8 24
Other income (expense) - net   15       12       16       19       62     49       15       14       78  
Income (loss) before income taxes 80 (157 ) 345 171 439 663 349 283 1,295
Provision (benefit) for income taxes   1       (80 )     (6 )     5       (80 )   3       1       (1 )     3  
Net income (loss) 79 (77 ) 351 166 519 660 348 284 1,292
Less: Net income attributable to noncontrolling interests   29       13       25       21       88     26       28       25       79  
Net income (loss) attributable to controlling interests $ 50     $ (90 )   $ 326     $ 145     $ 431   $ 634     $ 320     $ 259     $ 1,213  
 
Allocation of net income (loss) for calculation of earnings per common unit:
Net income (loss) attributable to controlling interests $ 50 $ (90 ) $ 326 $ 145 $ 431 $ 634 $ 320 $ 259 $ 1,213
Allocation of net income (loss) to general partner (1) 202 207 72 517
Allocation of net income (loss) to Class B units (1)   (4 )     (8 )     7       2       12     11       6       4       21  
Allocation of net income (loss) to common units (1) $ (148 )   $ (289 )   $ 247     $ 143     $ (98 ) $ 623     $ 314     $ 255     $ 1,192  
 
Diluted earnings (loss) per common unit:
Net income (loss) per common unit (1) $ (0.25 ) $ (0.49 ) $ 0.42 $ 0.24 $ (0.17 ) $ 0.68 $ 0.33 $ 0.27 $ 1.26
Weighted average number of common units outstanding (thousands) 588,562 588,607 591,567 601,738 592,519 920,250 955,986 956,365 944,333
 
Cash distributions per common unit $ 0.85 $ 0.85 $ 0.85 $ 0.85 $ 3.40 $ 0.60 $ 0.60 $ 0.60 $ 1.80
 
(1) The sum for the quarters may not equal the total for the year due to timing of unit issuances.
   
Williams Partners L.P.
Northeast G&P

(UNAUDITED)

 
2016   2017  
(Dollars in millions)   1st Qtr   2nd Qtr   3rd Qtr   4th Qtr   Year 1st Qtr   2nd Qtr   3rd Qtr   Year
                                     
Revenues:              
Service revenues:
Nonregulated gathering and processing fee-based revenue $ 186 $ 182 $ 179 $ 184 $ 731 $ 182 $ 183 $ 182 $ 547
Other fee revenues 37 40 39 42 158 40 38 36 114
Product sales:
NGL sales from gas processing 4 3 3 4 14 4 4 2 10
Marketing sales   19       31       40       58       148     64       48       59       171  
246 256 261 288 1,051 290 273 279 842
Intrasegment eliminations   (4 )     (6 )     (4 )     (5 )     (19 )   (5 )     (4 )     (4 )     (13 )
Total revenues 242 250 257 283 1,032 285 269 275 829
 
Segment costs and expenses:
NGL cost of goods sold 1 2 1 2 6 4 1 2 7
Marketing cost of goods sold 20 32 41 60 153 65 48 59 172
Other segment costs and expenses (1) 99 91 95 98 383 91 93 102 286
Impairment of certain assets 4 4 5 13 1 1 121 123
Intrasegment eliminations   (4 )     (6 )     (4 )     (5 )     (19 )   (5 )     (4 )     (4 )     (13 )
Total segment costs and expenses 120 123 133 160 536 156 139 280 575
 
Proportional Modified EBITDA of equity-method investments   98       95       90       74       357     97       117       120       334  
Modified EBITDA 220 222 214 197 853 226 247 115 588
Adjustments   5             6       22       33     1       1       131       133  
Adjusted EBITDA $ 225     $ 222     $ 220     $ 219     $ 886   $ 227     $ 248     $ 246     $ 721  
                                     
Statistics for Operated Assets
 
Gathering and Processing
Gathering volumes (Bcf per day) - Consolidated (2) 3.34 3.15 3.16 3.19 3.21 3.32 3.28 3.28 3.29
Gathering volumes (Bcf per day) - Non-consolidated (3) 3.21 3.16 3.08 3.20 3.16 3.55 3.58 3.48 3.54
Plant inlet natural gas volumes (Bcf per day) (2) 0.31 0.31 0.34 0.37 0.33 0.39 0.40 0.45 0.41
 
Ethane equity sales (Mbbls/d) 6 4 3 3 4 2 2 2 2
Non-ethane equity sales (Mbbls/d)   1       1       1       1       1     1       1       1       1  
NGL equity sales (Mbbls/d) 7 5 4 4 5 3 3 3 3
 
Ethane production (Mbbls/d) 14 18 22 20 18 17 22 17 19
Non-ethane production (Mbbls/d)   11       12       16       15       14     15       17       19       17  
NGL production (Mbbls/d) 25 30 38 35 32 32 39 36 36
 
(1)   Includes operating expenses, general and administrative expenses, and other income or expenses.
(2) Includes gathering volumes associated with Susquehanna Supply Hub, Ohio Valley Midstream, and Utica Supply Hub, all of which are consolidated.
(3) Includes 100% of the volumes associated with operated equity-method investments, including the Laurel Mountain Midstream partnership; and the Bradford Supply Hub and a portion of the Marcellus South Supply Hub within the Appalachia Midstream Services partnership. Volumes handled by Blue Racer Midstream (gathering and processing) and UEOM (processing only), which we do not operate, are not included.
   
Williams Partners L.P.
Atlantic-Gulf

(UNAUDITED)

 
2016   2017  
(Dollars in millions)   1st Qtr   2nd Qtr   3rd Qtr   4th Qtr   Year 1st Qtr   2nd Qtr   3rd Qtr   Year
                                     
Revenues:              
Service revenues:
Nonregulated gathering & processing fee-based revenue $ 92 $ 76 $ 131 $ 137 $ 436 $ 127 $ 136 $ 133 $ 396
Regulated transportation revenue 349 331 339 348 1,367 354 358 381 1,093
Other fee revenues 24 41 41 42 148 54 42 38 134
Product sales:
NGL sales from gas processing 8 11 24 31 74 27 16 13 56
Marketing sales 45 75 78 84 282 90 75 66 231
Other sales 4 4 8 1 1 2
Tracked revenues   38       39       51       39       167     36       52       47       135  
556 573 668 685 2,482 689 679 679 2,047
Intrasegment eliminations   (9 )     (10 )     (9 )     (6 )     (34 )   (19 )     (7 )     (9 )     (35 )
Total revenues 547 563 659 679 2,448 670 672 670 2,012
 
Segment costs and expenses:
NGL cost of goods sold 3 4 15 15 37 13 7 6 26
Marketing cost of goods sold 45 74 78 83 280 88 75 65 228
Other cost of goods sold 2 1 3
Impairment of certain assets 1 2 3
Other segment costs and expenses (1) 153 162 174 169 658 174 171 195 540
Tracked costs 38 39 51 39 167 36 52 47 135
Intrasegment eliminations   (9 )     (10 )     (9 )     (6 )     (34 )   (19 )     (7 )     (9 )     (35 )
Total segment costs and expenses 231 271 311 301 1,114 292 298 304 894
 
Proportional Modified EBITDA of equity-method investments   66       68       75       78       287     72       80       64       216  
Modified EBITDA 382 360 423 456 1,621 450 454 430 1,334
Adjustments   23       8       11             42     3       8       1       12  
Adjusted EBITDA $ 405     $ 368     $ 434     $ 456     $ 1,663   $ 453     $ 462     $ 431     $ 1,346  
                                     
Statistics for Operated Assets
Gathering, Processing and Crude Oil Transportation
Gathering volumes (Bcf per day) - Consolidated (2) 0.30 0.30 0.52 0.53 0.41 0.32 0.29 0.31 0.31
Gathering volumes (Bcf per day) - Non-consolidated (3) 0.53 0.54 0.60 0.60 0.56 0.55 0.54 0.39 0.49
Plant inlet natural gas volumes (Bcf per day) - Consolidated (2) 0.64 0.60 0.84 0.78 0.72 0.56 0.57 0.52 0.55
Plant inlet natural gas volumes (Bcf per day) - Non-consolidated (3) 0.56 0.54 0.60 0.60 0.57 0.54 0.53 0.39 0.49
 
Crude transportation volumes (Mbbls/d) 98 99 126 128 113 131 135 137 134
 
Consolidated (2)
Ethane margin ($/gallon) $ .03 $ .05 $ (.03 ) $ (.01 ) $ $ .02 $ .03 $ .04 $ .03
Non-ethane margin ($/gallon) $ .30 $ .38 $ .26 $ .35 $ .31 $ .42 $ .36 $ .53 $ .42
NGL margin ($/gallon) $ .21 $ .18 $ .16 $ .20 $ .19 $ .26 $ .23 $ .26 $ .25
 
Ethane equity sales (Mbbls/d) 2 6 6 8 5 6 4 4 5
Non-ethane equity sales (Mbbls/d)   4       4       11       12       8     9       6       3       6  
NGL equity sales (Mbbls/d) 6 10 17 20 13 15 10 7 11
 
Ethane production (Mbbls/d) 13 17 16 19 16 14 14 13 14
Non-ethane production (Mbbls/d)   20       20       31       30       25     20       19       18       19  
NGL production (Mbbls/d) 33 37 47 49 41 34 33 31 33
 
Non-consolidated (3)
NGL equity sales (Mbbls/d) 5 5 5 5 5 5 4 5 5
NGL production (Mbbls/d) 17 19 21 21 20 21 22 22 22
 
Transcontinental Gas Pipe Line
Throughput (Tbtu) 927.2 815.9 878.1 881.5 3,502.7 939.1 887.6 938.5 2,765.2
Avg. daily transportation volumes (Tbtu) 10.2 9.0 9.5 9.6 9.6 10.4 9.8 10.2 10.1
Avg. daily firm reserved capacity (Tbtu) 12.0 11.5 11.6 11.9 11.7 12.8 13.2 14.1 13.4
 
(1)   Includes operating expenses, general and administrative expenses, and other income or expenses.
(2) Excludes volumes associated with equity-method investments that are not consolidated in our results.
(3) Includes 100% of the volumes associated with operated equity-method investments.
   
Williams Partners L.P.
West

(UNAUDITED)

 
2016   2017  
(Dollars in millions)   1st Qtr   2nd Qtr   3rd Qtr   4th Qtr   Year 1st Qtr   2nd Qtr   3rd Qtr   Year
                                     
Revenues:              
Service revenues:
Nonregulated gathering & processing fee-based revenue $ 376 $ 379 $ 374 $ 593 $ 1,722 $ 364 $ 382 $ 398 $ 1,144
Regulated transportation revenue 118 111 114 117 460 117 112 113 342
Other fee revenues 42 44 43 44 173 43 38 39 120
Product sales:
NGL sales from gas processing 38 54 53 58 203 64 61 68 193
Olefin sales 1 1
Marketing sales 269 342 396 504 1,511 506 490 561 1,557
Other sales 6 4 5 4 19 6 8 12 26
Tracked revenues         1                   1           1             1  
849 935 985 1,320 4,089 1,101 1,092 1,191 3,384
Intrasegment eliminations   (76 )     (101 )     (95 )     (109 )     (381 )   (127 )     (130 )     (162 )     (419 )
Total revenues 773 834 890 1,211 3,708 974 962 1,029 2,965
 
Segment costs and expenses:
NGL cost of goods sold 18 22 26 25 91 27 31 31 89
Marketing cost of goods sold 271 345 396 494 1,506 505 498 550 1,553
Other cost of goods sold 5 3 5 3 16 5 4 12 21
Other segment costs and expenses (1) 252 231 223 235 941 204 220 209 633
Impairment of certain assets 1 49 1 49 100 1 1,021 1,022
Tracked costs 1 1 1 1
Intrasegment eliminations   (76 )     (101 )     (95 )     (109 )     (381 )   (127 )     (130 )     (162 )     (419 )
Total segment costs and expenses 471 550 556 697 2,274 614 624 1,662 2,900
 
Proportional Modified EBITDA of equity-method investments   25       28       29       28       110     25       18       18       61  
Modified EBITDA 327 312 363 542 1,544 385 356 (615 ) 126
Adjustments   73       112       70       (148 )     107     4       16       1,041       1,061  
Adjusted EBITDA $ 400     $ 424     $ 433     $ 394     $ 1,651   $ 389     $ 372     $ 426     $ 1,187  
                                     
Statistics for Operated Assets
Gathering and Processing
Gathering volumes (Bcf per day) 4.60 4.68 4.72 4.50 4.62 4.23 4.40 4.62 4.42
Plant inlet natural gas volumes (Bcf per day) 2.51 2.51 2.48 2.32 2.45 1.99 2.00 2.11 2.03
 
Ethane equity sales (Mbbls/d) 4 15 6 4 7 3 11 11 8
Non-ethane equity sales (Mbbls/d)   20       22       23       21       21     20       20       20       20  
NGL equity sales (Mbbls/d) 24 37 29 25 28 23 31 31 28
 
Ethane margin ($/gallon) $ .03 $ .00 $ .00 $ .00 $ .01 $ .04 $ .00 $ .02 $ .02
Non-ethane margin ($/gallon) $ .26 $ .39 $ .31 $ .41 $ .34 $ .49 $ .40 $ .45 $ .45
NGL margin ($/gallon) $ .22 $ .23 $ .24 $ .34 $ .26 $ .43 $ .26 $ .30 $ .32
 
Ethane production (Mbbls/d) 12 25 10 9 14 8 18 19 15
Non-ethane production (Mbbls/d)   64       66       65       62       64     55       57       62       58  
NGL production (Mbbls/d) 76 91 75 71 78 63 75 81 73
 
Northwest Pipeline LLC
Throughput (Tbtu) 205.6 168.0 161.9 191.6 727.1 219.0 165.4 156.4 540.8
Avg. daily transportation volumes (Tbtu) 2.3 1.8 1.8 2.1 2.0 2.4 1.8 1.7 2.0
Avg. daily firm reserved capacity (Tbtu) 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0
 
Overland Pass Pipeline Company LLC (equity investment) - 100%
NGL Transportation volumes (Mbbls) 16,814 18,410 18,535 18,078 71,837 18,338 20,558 21,015 59,911
 
(1)   Includes operating expenses, general and administrative expenses, and other income or expenses.
   
Williams Partners L.P.
NGL & Petchem Services

(UNAUDITED)

 
2016   2017  
(Dollars in millions)   1st Qtr   2nd Qtr   3rd Qtr   4th Qtr   Year 1st Qtr   2nd Qtr   3rd Qtr   Year
                                     
Revenues:              
Service revenue:
Nonregulated gathering & processing fee-based revenue $ 1 $ 4 $ $ $ 5 $ $ $ $
Other fee-based revenues 7 19 14 3 43 3 4 7
Product sales:
NGL sales from gas processing 17 3 16 36
Olefin sales 136 151 202 160 649 160 145 6 311
Marketing sales 28 27 45 39 139 56 38 3 97
Other sales               2             2                        
189 204 279 202 874 219 187 9 415
Intrasegment eliminations   (13 )     (8 )     (21 )     (5 )     (47 )   (17 )     (26 )           (43 )
Total revenues 176 196 258 197 827 202 161 9 372
 
Segment costs and expenses:
NGL cost of goods sold 12 2 10 24
Olefins cost of goods sold 65 77 84 86 312 89 93 4 186
Marketing cost of goods sold 28 29 41 40 138 52 40 3 95
Other cost of goods sold 1 2 3
Gain on sale of Geismar Interest (1,095 ) (1,095 )
Impairment of certain assets 341 1 342
Other segment costs and expenses (1) 57 45 72 26 200 27 24 13 64
Intrasegment eliminations   (13 )     (8 )     (21 )     (5 )     (47 )   (17 )     (26 )           (43 )
Total segment costs and expenses 150 486 188 148 972 151 131 (1,075 ) (793 )
                               
Modified EBITDA 26 (290 ) 70 49 (145 ) 51 30 1,084 1,165
Adjustments   4       341       32       (3 )     374     (2 )     (7 )     (1,083 )     (1,092 )
Adjusted EBITDA $ 30     $ 51     $ 102     $ 46     $ 229   $ 49     $ 23     $ 1     $ 73  
                                     
Statistics for Operated Assets
 
Ethane equity sales (Mbbls/d) 10 1 8 7
Non-ethane equity sales (Mbbls/d)   10       1       6             6                        
NGL equity sales (Mbbls/d) 20 2 14 13
 
Ethane production (Mbbls/d) 10 1 8
Non-ethane production (Mbbls/d)   8       2       8                                    
NGL production (Mbbls/d) 18 3 16
 
Petrochemical Services
Geismar ethylene sales volumes (million lbs) 423 391 419 405 1,638 266 300 566
Geismar ethylene margin ($/lb) (2) $ .13 $ .15 $ .21 $ .15 $ .16 $ .19 $ .13 $ $ .16
Canadian propylene sales volumes (millions lbs) 33 8 46 87
Canadian alky feedstock sales volumes (million gallons) 7 2 6 15
 
(1)   Includes operating expenses, general and administrative expenses, and other income or expenses.
(2) Ethylene margin and ethylene margin per pound are calculated using financial results determined in accordance with GAAP, which include realized ethylene sales prices and ethylene COGS. Realized sales and COGS per unit metrics may vary from publicly quoted market indices or spot prices due to various factors, including, but not limited to, basis differentials, transportation costs, contract provisions, and inventory accounting methods.
   
Williams Partners L.P.
Capital Expenditures and Investments

(UNAUDITED)

 
2016 2017  
(Dollars in millions)   1st Qtr   2nd Qtr   3rd Qtr   4th Qtr   Year 1st Qtr   2nd Qtr   3rd Qtr   Year
                                     
Capital expenditures:              
Northeast G&P $ 67 $ 55 $ 46 $ 56 $ 224 $ 58 $ 81 $ 173 $ 312
Atlantic-Gulf 300 410 380 345 1,435 388 398 371 1,157
West 62 33 63 70 228 57 58 94 209
NGL & Petchem Services 34 18 4 1 57 6 1 (1 ) 6
Other         2     (2 )                 2       1       3  
Total (1) $ 463     $ 518   $ 491     $ 472   $ 1,944 $ 509     $ 540     $ 638     $ 1,687  
 
Purchases of investments:
Northeast G&P $ 24 $ 40 $ (16 ) $ 24 $ 72 $ 20 $ 26 $ 24 $ 70
Atlantic-Gulf 1 1
West   39       19     26       21     105   32                   32  
Total $ 63     $ 59   $ 10     $ 45   $ 177 $ 52     $ 27     $ 24     $ 103  
 
Summary:
Northeast G&P $ 91 $ 95 $ 30 $ 80 $ 296 $ 78 $ 107 $ 197 $ 382
Atlantic-Gulf 300 410 380 345 1,435 388 399 371 1,158
West 101 52 89 91 333 89 58 94 241
NGL & Petchem Services 34 18 4 1 57 6 1 (1 ) 6
Other         2     (2 )                 2       1       3  
Total $ 526     $ 577   $ 501     $ 517   $ 2,121 $ 561     $ 567     $ 662     $ 1,790  
 
Capital expenditures incurred and purchases of investments:
Increases to property, plant, and equipment $ 498 $ 485 $ 446 $ 442 $ 1,871 $ 569 $ 586 $ 660 $ 1,815
Purchases of investments   63       59     10       45     177   52       27       24       103  
Total $ 561     $ 544   $ 456     $ 487   $ 2,048 $ 621     $ 613     $ 684     $ 1,918  
 
(1) Increases to property, plant, and equipment $ 498 $ 485 $ 446 $ 442 $ 1,871 $ 569 $ 586 $ 660 $ 1,815
Changes in related accounts payable and accrued liabilities   (35 )     33     45       30     73   (60 )     (46 )     (22 )     (128 )
Capital expenditures $ 463     $ 518   $ 491     $ 472   $ 1,944 $ 509     $ 540     $ 638     $ 1,687  
   
Selected Financial Information

(UNAUDITED)

 
2016 2017
(Dollars in millions)   1st Qtr   2nd Qtr   3rd Qtr   4th Qtr 1st Qtr   2nd Qtr   3rd Qtr
                             
Cash and cash equivalents $ 125   $ 101   $ 68   $ 145 $ 625   $ 1,908   $ 1,165
 
Capital structure:
Debt:
Commercial paper $ 135 $ 196 $ 2 $ 93 $ $ $
Current $ 976 $ 786 $ 785 $ 785 $ $ 1,951 $ 502
Noncurrent $ 18,504 $ 19,116 $ 18,918 $ 17,685 $ 17,065 $ 16,614 $ 16,000

Contact:

Williams Partners L.P.
Media Contact:
Keith Isbell, 918-573-7308
or
Investor Contact:
Brett Krieg, 918-573-4614