TULSA, Okla.--(BUSINESS WIRE)--Williams Partners L.P. (NYSE: WPZ) today announced its financial results for the three and six months ended June 30, 2017.
| Summary Financial Information | 2Q | YTD | |||||||||||||||||
| Amounts in millions, except per-unit amounts. Per unit amounts are reported on a diluted basis. All amounts are attributable to Williams Partners L.P. | 2017 | 2016 | 2017 | 2016 | |||||||||||||||
| GAAP Measures | |||||||||||||||||||
| Cash Flow from Operations | $ | 776 | $ | 742 | $ | 1,507 | $ | 1,666 | |||||||||||
| Net income (loss) | $ | 320 | ($90 | ) | $ | 954 | ($40 | ) | |||||||||||
| Net income (loss) per common unit | $ | 0.33 | ($0.49 | ) | $ | 1.00 | ($0.74 | ) | |||||||||||
| Non-GAAP Measures (1) | |||||||||||||||||||
| Adjusted EBITDA | $ | 1,104 | $ | 1,065 | $ | 2,221 | $ | 2,125 | |||||||||||
| DCF attributable to partnership operations | $ | 698 | $ | 737 | $ | 1,450 | $ | 1,476 | |||||||||||
| Cash distribution coverage ratio | 1.22x | 1.02x | 1.27x | 1.02x | |||||||||||||||
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(1) Adjusted EBITDA, distributable cash flow (DCF) and cash distribution coverage ratio are non-GAAP measures. Reconciliations to the most relevant measures included in GAAP are attached to this news release. |
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Second-Quarter 2017 Financial Results
Williams Partners reported unaudited second-quarter 2017 net income attributable to controlling interests of $320 million, a $410 million improvement over second-quarter 2016. The favorable change was driven by a $452 million improvement in operating income primarily reflecting a $394 million decrease in impairments of certain assets and increased fee-based revenue from expansion projects. The decrease in impairments includes the absence of a second-quarter 2016, $341 million impairment charge associated with the partnership’s now former Canadian business that was sold in September 2016.
Year-to-date, Williams Partners reported unaudited net income of $954 million, a $994 million improvement over the same period in 2016. The favorable change was driven by a $593 million improvement in operating income primarily reflecting a $399 million decrease in impairments of certain assets and increased fee-based revenue from expansion projects. The decrease in impairments includes the absence of the impairment charge referenced above. The improvement in net income also reflects a gain of $269 million associated with the disposition of certain equity-method investments in 2017 and the absence of $112 million of impairments of equity-method investments incurred in 2016.
Williams Partners reported second-quarter 2017 Adjusted EBITDA of $1.104 billion, a $39 million increase over second-quarter 2016. The improvement is due primarily to $18 million increased fee-based revenues and a $24 million increase in proportional EBITDA of joint ventures. Partially offsetting these increases were $22 million lower olefins margins.
Year-to-date, Williams Partners reported Adjusted EBITDA of $2.221 billion, an increase of $96 million over the same six-month reporting period in 2016. The increase is due primarily to $36 million lower operating and maintenance (O&M) and selling, general and administrative (SG&A) expenses, a $28 million improvement in other income and expense, and a $29 million increase in proportional EBITDA of joint ventures.
Distributable Cash Flow and Distributions
For second-quarter 2017, Williams Partners generated $698 million in distributable cash flow (DCF) attributable to partnership operations, compared with $737 million in DCF attributable to partnership operations for second-quarter 2016. DCF for second-quarter 2017 has been reduced by $58 million for the planned removal of non-cash deferred revenue amortization associated with the fourth-quarter 2016 contract restructuring in the Barnett Shale and Mid-Continent region. Also impacting the unfavorable change were $25 million increased maintenance capital expenditures and a $19 million increase in income attributable to non-controlling interests. Partially offsetting the unfavorable changes was the previously described improvement in the quarter’s Adjusted EBITDA and a $29 million decrease in interest expense. For second-quarter 2017, the cash distribution coverage ratio was 1.22x.
Year-to-date, Williams Partners generated $1.450 billion in DCF, a decrease of $26 million over the same period in 2016. DCF for 2017 has been reduced by $116 million for the planned removal of non-cash deferred revenue amortization associated with the fourth-quarter 2016 contract restructuring in the Barnett Shale and Mid-Continent region. Also impacting the unfavorable change were $20 million increased maintenance capital expenditures and a $17 million increase in income attributable to non-controlling interests. Partially offsetting the unfavorable changes were the previously described improvement in year-to-date Adjusted EBITDA and a $46 million decrease in interest expense. The cash distribution coverage for the first six-month reporting period was 1.27x.
Williams Partners recently announced a regular quarterly cash distribution of $0.60 per unit, payable Aug. 11, 2017, to its common unitholders of record at the close of business on Aug. 4, 2017.
CEO Perspective
Alan Armstrong, chief executive officer of Williams Partners’ general partner, made the following comments:
“The second quarter demonstrated once again the long-term, sustainable benefits of our focused strategy as we recognized year-over-year growth in Adjusted EBITDA for the 15th consecutive quarter. We met or exceeded business performance expectations in all three remaining business units, offset by weaker than expected performance at Geismar, which was impacted by a continuing outage and lower margins. Strong performance in the Atlantic-Gulf, coupled with expected growth for the balance of the year, gives us confidence in achieving our prior guidance on Adjusted EBITDA and DCF.
“We continue to deliver on project execution as planned for 2017. So far this year, we have successfully brought into service three Transco expansion projects including the 1.2 Bcf/d Gulf Trace project, the 0.8 Bcf/d Hillabee Phase 1 project, and just this week, the 0.4 Bcf/d Dalton Expansion project. The line of sight to future growth is evident as well as we are targeting second-half 2017 in-service dates for three more fully-contracted growth projects including Virginia Southside II, New York Bay, and Garden State Phase 1.
“In addition to strong year-over-year fee-based revenue growth in the Atlantic-Gulf, we also saw gathered volumes in the West up approximately 4 percent versus first-quarter 2017, adjusted for the Marcellus-for-Permian transaction. While pipeline takeaway constraints continue to impact volumes in the Northeast, we remain well-positioned for volume growth as those constraints are lifted. We’re also pleased our Susquehanna and Ohio River Systems delivered year-over-year fee-based revenue growth. As we look ahead, around 97 percent of our gross margins will come from predictable fee-based sources now that we have successfully completed the sale of Geismar – reducing our commodity exposure and further strengthening our natural gas-focused strategy.
“We continue to see benefits from the reorganization of our operating areas and operational support functions such as safety and procurement. Continuous improvement in safety performance and project execution is another commitment that we are delivering on at the mid-point of 2017 and will continue to focus on as we move through the second half of the year.”
Business Segment Results
Effective, Jan. 1, 2017, Williams Partners implemented certain changes in its reporting segments as part of an operational realignment. As a result beginning with the reporting of first-quarter 2017 financial results, Williams Partners operations are comprised of the following reportable segments: Atlantic-Gulf, West, Northeast G&P, and NGL & Petchem Services.
| Williams Partners | Modified and Adjusted EBITDA | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Amounts in millions | 2Q 2017 | 2Q 2016 | YTD 2017 | YTD 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Modified EBITDA | Adjust. | Adjusted EBITDA | Modified EBITDA | Adjust. | Adjusted EBITDA | Modified EBITDA | Adjust. | Adjusted EBITDA | Modified EBITDA | Adjust. | Adjusted EBITDA | |||||||||||||||||||||||||||||||||||||||||||||
| Atlantic-Gulf | $ | 454 | $ | 8 | $ | 462 | $ | 360 | $ | 8 | $ | 368 | $ | 904 | $ | 11 | $ | 915 | $ | 742 | $ | 31 | $ | 773 | ||||||||||||||||||||||||||||||||
| West | 356 | 16 | 372 | 312 | 112 | 424 | 741 | 20 | 761 | 639 | 185 | 824 | ||||||||||||||||||||||||||||||||||||||||||||
| Northeast G&P | 247 | 1 | 248 | 222 | - | 222 | 473 | 2 | 475 | 442 | 5 | 447 | ||||||||||||||||||||||||||||||||||||||||||||
| NGL & Petchem Services | 30 | (7 | ) | 23 | (290 | ) | 341 | 51 | 81 | (9 | ) | 72 | (264 | ) | 345 | 81 | ||||||||||||||||||||||||||||||||||||||||
| Other | (11 | ) | 10 | (1 | ) | - | - | - | 9 | (11 | ) | (2 | ) | - | - | - | ||||||||||||||||||||||||||||||||||||||||
| Total | $ | 1,076 | $ | 28 | $ | 1,104 | $ | 604 | $ | 461 | $ | 1,065 | $ | 2,208 | $ | 13 | $ | 2,221 | $ | 1,559 | $ | 566 | $ | 2,125 | ||||||||||||||||||||||||||||||||
| Definitions of modified EBITDA and adjusted EBITDA and schedules reconciling these measures to net income are included in this news release. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Atlantic-Gulf
This segment includes the partnership’s interstate natural gas pipeline, Transco, and significant natural gas gathering and processing and crude oil production handling and transportation assets in the Gulf Coast region, including a 51 percent interest in Gulfstar One (a consolidated entity), which is a proprietary floating production system, and various petrochemical and feedstock pipelines in the Gulf Coast region, as well as a 50 percent equity-method investment in Gulfstream, a 41 percent interest in Constitution (a consolidated entity) which is under development, and a 60 percent equity-method investment in Discovery.
The Atlantic-Gulf segment reported Modified EBITDA of $454 million for second-quarter 2017, compared with $360 million for second-quarter 2016. Adjusted EBITDA increased by $94 million to $462 million for the same reporting period. The increase in both measures was driven primarily by $88 million increased fee-based revenues due primarily to higher volumes from Gulfstar One and Transco expansion projects placed in service, as well as higher proportional EBITDA from joint ventures related to an $11 million increase from Discovery. Partially offsetting the favorable results were $14 million in increased O&M expenses due primarily to higher costs associated with Transco’s integrity and pipeline maintenance program.
Year-to-date, the Atlantic-Gulf segment reported Modified EBITDA of $904 million, an increase of $162 million over the same six-month period in 2016. Adjusted EBITDA increased $142 million to $915 million. The drivers for the increase in both measures are an improvement in fee-based revenues due primarily to higher volumes from Gulfstar One and Transco expansion projects placed in service, $18 million higher proportional EBITDA from joint ventures primarily from Discovery, and $13 million higher commodity margins. Partially offsetting these improvements were increased O&M expenses due primarily to higher costs associated with Transco’s integrity and pipeline maintenance program and the segment’s offshore business.
West
This segment includes the partnership’s interstate natural gas pipeline, Northwest Pipeline, and natural gas gathering, processing, and treating operations in New Mexico, Colorado, and Wyoming, as well as the Barnett Shale region of north-central Texas, the Eagle Ford Shale region of south Texas, the Haynesville Shale region of northwest Louisiana, and the Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian basins. This reporting segment also includes an NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, and a 50 percent equity-method investment in OPPL. The partnership completed the sale of its 50 percent equity-method investment in a Delaware Basin gas gathering system in the Mid-Continent region during first-quarter 2017.
The West segment reported Modified EBITDA of $356 million for second-quarter 2017, compared with $312 million for second-quarter 2016. Adjusted EBITDA decreased by $52 million to $372 million. The increase in Modified EBITDA was driven primarily by the absence of $48 million of impairments that impacted second-quarter 2016, which are excluded from Adjusted EBITDA. The decrease in Adjusted EBITDA was due primarily to $51 million lower fee-based revenues, including $18 million lower fee-based revenues in the Barnett from lower volumes and contract changes that occurred during 2016. Revenues in the Niobrara decreased by $7 million due to a change in revenue recognition timing resulting from contract restructuring. The unfavorable change in Adjusted EBITDA was also impacted by $10 million in decreased proportional EBITDA of joint ventures, due in part to the partnership’s sale of its interests in certain non-operated Delaware Basin assets in first-quarter 2017. Volume decreases in other areas also contributed to the unfavorable change. Partially offsetting the decrease was a $14 million decline in O&M and SG&A expenses.
Year-to-date, the West segment reported Modified EBITDA of $741 million, an increase of $102 million over the same six-month period in 2016. Adjusted EBITDA decreased by $63 million to $761 million. The increase in Modified EBITDA was driven primarily by a $65 million improvement in other income and expense, which included the absence of the impairments that impacted second-quarter 2016 and are excluded from Adjusted EBITDA. The favorable change also reflects $46 million in reduced O&M and SG&A expenses, $8 million of which are excluded from the Adjusted EBITDA measure. The decrease in Adjusted EBITDA was driven primarily by $108 million lower fee-based revenues, including $44 million lower fee-based revenues in the Barnett from lower volumes and contract changes that occurred during 2016. Revenues in the Niobrara decreased by $17 million due to a change in revenue recognition timing resulting from contract restructuring. The unfavorable change in Adjusted EBITDA was also impacted by $10 million in decreased proportional EBITDA of joint ventures, due in part to the partnership’s sale of its interests in certain non-operated Delaware Basin assets in first-quarter 2017. Volume decreases in other areas also contributed to the unfavorable change. Partially offsetting the decreases were the reduced O&M and SG&A expenses described above and $17 million in improved commodity margins.
Northeast G&P
This segment includes the partnership’s natural gas gathering and processing, compression and NGL fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and West Virginia and Utica Shale region of eastern Ohio, as well as a 66 percent interest in Cardinal (a consolidated entity), a 62 percent equity-method investment in Utica East Ohio Midstream (UEOM), a 69 percent equity-method investment in Laurel Mountain, a 58 percent equity-method investment in Caiman II, and Appalachia Midstream Services, LLC, which owns an approximate average 66 percent equity-method investment in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
The Northeast G&P segment reported Modified EBITDA of $247 million for second-quarter 2017, compared with $222 million for second-quarter 2016. Adjusted EBITDA increased by $26 million to $248 million. The improvement in both measures was driven primarily by a $22 million increase in proportional EBITDA of joint ventures due largely to the partnership’s increase in ownership in two Marcellus shale gathering systems in first-quarter 2017. Fee-based revenues were stable between the two periods due to increases in the Susquehanna and Ohio River systems that offset decreases in the Utica.
Year-to-date, the Northeast G&P segment reported Modified EBITDA of $473 million, an increase of $31 million over the same six-month period in 2016. Adjusted EBITDA increased by $28 million to $475 million. The improvement in both measures was driven primarily by a $21 million increase in proportional EBITDA of joint ventures due largely to the partnership’s increase in ownership in two Marcellus shale gathering systems in first-quarter 2017. Fee-based revenues were stable between the two periods due to increases in the Susquehanna and Ohio River systems that offset decreases in the Utica.
NGL & Petchem Services
On Jan. 1, 2017 this segment included the partnership’s 88.46 percent undivided interest in an olefins production facility in Geismar, Louisiana, along with a refinery grade propylene splitter. On July 6, 2017, the partnership announced that it had completed the sale of all of its membership interest in the Geismar olefins production facility and associated complex. On June 30, 2017 the partnership completed the sale of the refinery grade propylene splitter. Prior to September 2016, this reporting segment also included an oil sands offgas processing plant near Fort McMurray, Alberta, and an NGL/olefin fractionation facility, which were subsequently sold.
The NGL & Petchem Services segment reported Modified EBITDA of $30 million for second-quarter 2017, compared with ($290) million for second-quarter 2016. Adjusted EBITDA decreased by $28 million to $23 million. The favorable change in Modified EBITDA was driven primarily by the absence of a second-quarter 2016, $341 million impairment charge associated with Williams Partners’ now former Canadian business that was sold in September 2016. Adjusted EBITDA was unfavorably impacted by a $22 million decrease in olefins margins due primarily to lower volumes at the Geismar olefins plant due to an unexpected power outage at the plant that resulted in the facility being offline from March 12 until restarting on April 18, 2017. Lower volumes at the RGP Splitter in connection with its sale on June 30 also contributed to the unfavorable change. The quarter’s unfavorable change in Adjusted EBITDA also reflects a $19 million decrease in fee-based revenues due primarily to the third-quarter 2016 sale of the partnership’s now former Canadian business. Partially offsetting these decreases was a $15 million reduction in O&M and SG&A expenses due primarily to the September 2016 sale of the partnership’s now former Canadian business.
Year-to-date, the NGL & Petchem Services segment reported Modified EBITDA of $81 million, an improvement of $345 million over the same six-month period in 2016. Adjusted EBITDA decreased $9 million to $72 million. The favorable change in Modified EBITDA was driven primarily by the absence of a second-quarter 2016, $341 million impairment charge associated with Williams Partners’ now former Canadian business that was sold in September 2016. Adjusted EBITDA was unfavorably impacted by a $24 million decrease in fee-based revenues and a $22 million decrease in olefins margins due primarily to lower volumes. The Geismar olefins plant had lower volumes due to the previously described power outage. The segment’s lower fee-based revenues and olefins margins also reflect the sale of the partnership’s now former Canadian business in September 2016. Partially offsetting these decreases was a $28 million reduction in O&M and SG&A expenses due primarily to the third-quarter 2016 sale of Williams Partners’ now former Canadian business.
Williams Partners does not expect significant future operating results from this segment; however, as a result of the sale of its interest in the Geismar olefins facility referenced above, the partnership expects to record a gain of approximately $1.1 billion in the third quarter of 2017.
Atlantic Sunrise Update
Williams Partners received notice to proceed on the mainline portion of the project, and construction activities are underway. In third-quarter 2017, the partnership expects to begin early mainline service and to receive final permits on the greenfield portion of the project. Williams Partners continues to target mid-2018 for the project’s full in-service date.
Guidance
The Guidance previously provided at our Analyst Day event on May 11, 2017, remains unchanged.
Williams Partners’ Second-Quarter 2017 Materials to be Posted Shortly; Q&A Webcast Scheduled for Tomorrow
Williams Partners’ second-quarter 2017 financial results package will be posted shortly at www.williams.com. The materials will include the analyst package.
Williams Partners and Williams will host a joint Q&A live webcast on Thursday, Aug. 3 at 9:30 a.m. Eastern Daylight Time (8:30 a.m. Central Daylight Time). A limited number of phone lines will be available at (877) 419-6594. International callers should dial (719) 325-4888. The conference ID is 9171330. The link to the webcast, as well as replays of the webcast, will be available for at least 90 days following the event at www.williams.com.
Form 10-Q
The partnership plans to file its second-quarter 2017 Form 10-Q with the Securities and Exchange Commission (SEC) this week. Once filed, the document will be available on both the SEC and Williams Partners websites.
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 permits 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 our risk factors in addition to the other information provided herein. If any of the risks to which we are exposed were actually to occur, our business, results of operations, and financial condition could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and unitholders could lose all or part of their investment.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February 22, 2017.
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| Reconciliation of Non-GAAP Measures | |||||||||||||||||||||||||||||||||||||||||
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(UNAUDITED) |
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| 2016 | 2017 | ||||||||||||||||||||||||||||||||||||||||
| (Dollars in millions, except coverage ratios) | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | 1st Qtr | 2nd Qtr | Year | |||||||||||||||||||||||||||||||||
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| Reconciliation of GAAP "Net Income (Loss)" to Non-GAAP "Modified EBITDA", "Adjusted EBITDA", and "Distributable cash flow” | |||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | $ | 79 | $ | (77 | ) | $ | 351 | $ | 166 | $ | 519 | $ | 660 | $ | 348 | $ | 1,008 | ||||||||||||||||||||||||
| Provision (benefit) for income taxes | 1 | (80 | ) | (6 | ) | 5 | (80 | ) | 3 | 1 | 4 | ||||||||||||||||||||||||||||||
| Interest expense | 229 | 231 | 229 | 227 | 916 | 214 | 205 | 419 | |||||||||||||||||||||||||||||||||
| Equity (earnings) losses | (97 | ) | (101 | ) | (104 | ) | (95 | ) | (397 | ) | (107 | ) | (125 | ) | (232 | ) | |||||||||||||||||||||||||
| Impairment of equity-method investments | 112 | — | — | 318 | 430 | — | — | — | |||||||||||||||||||||||||||||||||
| Other investing (income) loss | — | (1 | ) | (28 | ) | — | (29 | ) | (271 | ) | (2 | ) | (273 | ) | |||||||||||||||||||||||||||
| Proportional Modified EBITDA of equity-method investments | 189 | 191 | 194 | 180 | 754 | 194 | 215 | 409 | |||||||||||||||||||||||||||||||||
| Depreciation and amortization expenses | 435 | 432 | 426 | 427 | 1,720 | 433 | 423 | 856 | |||||||||||||||||||||||||||||||||
| Accretion for asset retirement obligations associated with nonregulated operations | 7 | 9 | 8 | 7 | 31 | 6 | 11 | 17 | |||||||||||||||||||||||||||||||||
| Modified EBITDA | 955 | 604 | 1,070 | 1,235 | 3,864 | 1,132 | 1,076 | 2,208 | |||||||||||||||||||||||||||||||||
| Adjustments | |||||||||||||||||||||||||||||||||||||||||
| Estimated minimum volume commitments | 60 | 64 | 70 | (194 | ) | — | 15 | 15 | 30 | ||||||||||||||||||||||||||||||||
| Severance and related costs | 25 | — | — | 12 | 37 | 9 | 4 | 13 | |||||||||||||||||||||||||||||||||
| Potential rate refunds associated with rate case litigation | 15 | — | — | — | 15 | — | — | — | |||||||||||||||||||||||||||||||||
| Merger and transition related expenses | 5 | — | — | — | 5 | — | 4 | 4 | |||||||||||||||||||||||||||||||||
| Constitution Pipeline project development costs | — | 8 | 11 | 9 | 28 | 2 | 6 | 8 | |||||||||||||||||||||||||||||||||
| Share of impairment at equity-method investment | — | — | 6 | 19 | 25 | — | — | — | |||||||||||||||||||||||||||||||||
| Geismar Incident adjustment for insurance and timing | — | — | — | (7 | ) | (7 | ) | (9 | ) | 2 | (7 | ) | |||||||||||||||||||||||||||||
| Impairment of certain assets | — | 389 | — | 22 | 411 | — | — | — | |||||||||||||||||||||||||||||||||
| Organizational realignment-related costs | — | — | — | 24 | 24 | 4 | 6 | 10 | |||||||||||||||||||||||||||||||||
| Loss related to Canada disposition | — | — | 32 | 2 | 34 | (3 | ) | (1 | ) | (4 | ) | ||||||||||||||||||||||||||||||
| Gain on asset retirement | — | — | — | (11 | ) | (11 | ) | — | — | — | |||||||||||||||||||||||||||||||
| Gains from contract settlements and terminations | — | — | — | — | — | (13 | ) | (2 | ) | (15 | ) | ||||||||||||||||||||||||||||||
| Accrual for loss contingency | — | — | — | — | — | 9 | — | 9 | |||||||||||||||||||||||||||||||||
| Gain on early retirement of debt | — | — | — | — | — | (30 | ) | — | (30 | ) | |||||||||||||||||||||||||||||||
| Gain on sale of RGP Splitter | — | — | — | — | — | — | (12 | ) | (12 | ) | |||||||||||||||||||||||||||||||
| Expenses associated with Financial Repositioning | — | — | — | — | — | — | 2 | 2 | |||||||||||||||||||||||||||||||||
| Expenses associated with strategic asset monetizations | — | — | — | 2 | 2 | 1 | 4 | 5 | |||||||||||||||||||||||||||||||||
| Total EBITDA adjustments | 105 | 461 | 119 | (122 | ) | 563 | (15 | ) | 28 | 13 | |||||||||||||||||||||||||||||||
| Adjusted EBITDA | 1,060 | 1,065 | 1,189 | 1,113 | 4,427 | 1,117 | 1,104 | 2,221 | |||||||||||||||||||||||||||||||||
| Maintenance capital expenditures (1) | (58 | ) | (75 | ) | (121 | ) | (147 | ) | (401 | ) | (53 | ) | (100 | ) | (153 | ) | |||||||||||||||||||||||||
| Interest expense (cash portion) (2) | (241 | ) | (245 | ) | (244 | ) | (239 | ) | (969 | ) | (224 | ) | (216 | ) | (440 | ) | |||||||||||||||||||||||||
| Cash taxes | — | — | — | (3 | ) | (3 | ) | (5 | ) | (1 | ) | (6 | ) | ||||||||||||||||||||||||||||
| Income attributable to noncontrolling interests (3) | (29 | ) | (13 | ) | (31 | ) | (27 | ) | (100 | ) | (27 | ) | (32 | ) | (59 | ) | |||||||||||||||||||||||||
| WPZ restricted stock unit non-cash compensation | 7 | 5 | 2 | 2 | 16 | 2 | 1 | 3 | |||||||||||||||||||||||||||||||||
| Amortization of deferred revenue associated with certain 2016 contract restructurings | — | — | — | — | — | (58 | ) | (58 | ) | (116 | ) | ||||||||||||||||||||||||||||||
| Distributable cash flow attributable to Partnership Operations (4) | 739 | 737 | 795 | 699 | 2,970 | 752 | 698 | 1,450 | |||||||||||||||||||||||||||||||||
| Total cash distributed (5) | $ | 725 | $ | 725 | $ | 734 | $ | 762 | $ | 2,946 | $ | 567 | $ | 574 | $ | 1,141 | |||||||||||||||||||||||||
| Coverage ratios: | |||||||||||||||||||||||||||||||||||||||||
| Distributable cash flow attributable to partnership operations divided by Total cash distributed | 1.02 | 1.02 | 1.08 | 0.92 | 1.01 | 1.33 | 1.22 | 1.27 | |||||||||||||||||||||||||||||||||
| Net income (loss) divided by Total cash distributed | 0.11 | (0.11 | ) | 0.48 | 0.22 | 0.18 | 1.16 | 0.61 | 0.88 | ||||||||||||||||||||||||||||||||
| (1) | Includes proportionate share of maintenance capital expenditures of equity investments. | |||
| (2) | Includes proportionate share of interest expense of equity investments. | |||
| (3) | Excludes allocable share of certain EBITDA adjustments. | |||
| (4) | The fourth quarter of 2016 includes income of $183 million associated with proceeds from the contract restructuring in the Barnett Shale and Mid-Continent region as the cash was received during 2016. | |||
| (5) | In order to exclude the impact of the IDR waiver associated with the WPZ merger termination fee from the determination of coverage ratios, cash distributions have been increased by $10 million in the first quarter of 2016. Cash distributions for the third quarter of 2016 have been increased to exclude the impact of the $150 million IDR waiver associated with the sale of our Canadian operations. Cash distributions for the fourth quarter of 2016 and the first quarter of 2017 have been decreased by $50 million and $6 million, respectively, to reflect the amount paid by WMB to WPZ pursuant to the January 2017 Common Unit Purchase Agreement. | |||
| Williams Partners L.P. | |||||||||||||||||||||||||||||||||||||||
| Reconciliation of Non-GAAP “Modified EBITDA” to Non-GAAP “Adjusted EBITDA” | |||||||||||||||||||||||||||||||||||||||
| (UNAUDITED) | |||||||||||||||||||||||||||||||||||||||
| 2016 | 2017 | ||||||||||||||||||||||||||||||||||||||
| (Dollars in millions) | 1st Qtr | 2nd Qtr | 3rd Qtr | 4th Qtr | Year | 1st Qtr | 2nd Qtr | Year | |||||||||||||||||||||||||||||||
| Modified EBITDA: | |||||||||||||||||||||||||||||||||||||||
| Northeast G&P | $ | 220 | $ | 222 | $ | 214 | $ | 197 | $ | 853 | $ | 226 | $ | 247 | $ | 473 | |||||||||||||||||||||||
| Atlantic-Gulf | 382 | 360 | 423 | 456 | 1,621 | 450 | 454 | 904 | |||||||||||||||||||||||||||||||
| West | 327 | 312 | 363 | 542 | 1,544 | 385 | 356 | 741 | |||||||||||||||||||||||||||||||
| NGL & Petchem Services | 26 | (290 | ) | 70 | 49 | (145 | ) | 51 | 30 | 81 | |||||||||||||||||||||||||||||
| Other | — | — | — | (9 | ) | (9 | ) | 20 | (11 | ) | 9 | ||||||||||||||||||||||||||||
| Total Modified EBITDA | $ | 955 | $ | 604 | $ | 1,070 | $ | 1,235 | $ | 3,864 | $ | 1,132 | $ | 1,076 | $ | 2,208 | |||||||||||||||||||||||
| Adjustments: | |||||||||||||||||||||||||||||||||||||||
|
Northeast G&P |
|||||||||||||||||||||||||||||||||||||||
| Severance and related costs | $ | 3 | $ | — | $ | — | $ | — | $ | 3 | $ | — | $ | — | $ | — | |||||||||||||||||||||||
| Share of impairment at equity-method investments | — | — | 6 | 19 | 25 | — | — | — | |||||||||||||||||||||||||||||||
| ACMP Merger and transition costs | 2 | — | — | — | 2 | — | — | — | |||||||||||||||||||||||||||||||
| Organizational realignment-related costs | — | — | — | 3 | 3 | 1 | 1 | 2 | |||||||||||||||||||||||||||||||
| Total Northeast G&P adjustments | 5 | — | 6 | 22 | 33 | 1 | 1 | 2 | |||||||||||||||||||||||||||||||
|
Atlantic-Gulf |
|||||||||||||||||||||||||||||||||||||||
| Potential rate refunds associated with rate case litigation | 15 | — | — | — | 15 | — | — | — | |||||||||||||||||||||||||||||||
| Severance and related costs | 8 | — | — | — | 8 | — | — | — | |||||||||||||||||||||||||||||||
| Constitution Pipeline project development costs | — | 8 | 11 | 9 | 28 | 2 | 6 | 8 | |||||||||||||||||||||||||||||||
| Organizational realignment-related costs | — | — | — | — | — | 1 | 2 | 3 | |||||||||||||||||||||||||||||||
| Gain on asset retirement | — | — | — | (11 | ) | (11 | ) | — | — | — | |||||||||||||||||||||||||||||
| Total Atlantic-Gulf adjustments | 23 | 8 | 11 | (2 | ) | 40 | 3 | 8 | 11 | ||||||||||||||||||||||||||||||
|
West |
|||||||||||||||||||||||||||||||||||||||
| Estimated minimum volume commitments | 60 | 64 | 70 | (194 | ) | — | 15 | 15 | 30 | ||||||||||||||||||||||||||||||
| Severance and related costs | 10 | — | — | 3 | 13 | — | — | — | |||||||||||||||||||||||||||||||
| ACMP Merger and transition costs | 3 | — | — | — | 3 | — | — | — | |||||||||||||||||||||||||||||||
| Impairment of certain assets | — | 48 | — | 22 | 70 | — | — | — | |||||||||||||||||||||||||||||||
| Organizational realignment-related costs | — | — | — | 21 | 21 | 2 | 3 | 5 | |||||||||||||||||||||||||||||||
|
Gains from contract settlements and terminations |
— | — | — | — | — | (13 | ) | (2 | ) | (15 | ) | ||||||||||||||||||||||||||||
| Total West adjustments | 73 | 112 | 70 | (148 | ) | 107 | 4 | 16 | 20 | ||||||||||||||||||||||||||||||
|
NGL & Petchem Services |
|||||||||||||||||||||||||||||||||||||||
| Impairment of certain assets | — | 341 | — | — | 341 | — | — | — | |||||||||||||||||||||||||||||||
| Loss related to Canada disposition | — | — | 32 | 2 | 34 | (3 | ) | (1 | ) | (4 | ) | ||||||||||||||||||||||||||||
| Severance and related costs | 4 | — | — | — | 4 | — | — | — | |||||||||||||||||||||||||||||||
| Expenses associated with strategic asset monetizations | — | — | — | 2 | 2 | 1 | 4 | 5 | |||||||||||||||||||||||||||||||
| Geismar Incident adjustment for insurance and timing | — | — | — | (7 | ) | (7 | ) | (9 | ) | 2 | (7 | ) | |||||||||||||||||||||||||||
| Gain on sale of RGP Splitter | — | — | — | — | — | — | (12 | ) | (12 | ) | |||||||||||||||||||||||||||||
| Accrual for loss contingency | — | — | — | — | — | 9 | — | 9 | |||||||||||||||||||||||||||||||
| Total NGL & Petchem Services adjustments | 4 | 341 | 32 | (3 | ) | 374 | (2 | ) | (7 | ) | (9 | ) | |||||||||||||||||||||||||||
|
Other |
|||||||||||||||||||||||||||||||||||||||
| Severance and related costs | — | — | — | 9 | 9 | 9 | 4 | 13 | |||||||||||||||||||||||||||||||
| ACMP Merger-related expenses | — | — | — | — | — | — | 4 | 4 | |||||||||||||||||||||||||||||||
| Expenses associated with Financial Repositioning | — | — | — | — | — | — | 2 | 2 | |||||||||||||||||||||||||||||||
| Gain on early retirement of debt | — | — | — | — | — | (30 | ) | — | (30 | ) | |||||||||||||||||||||||||||||
| Total Other adjustments | — | — | — | 9 | 9 | (21 | ) | 10 | (11 | ) | |||||||||||||||||||||||||||||
| Total Adjustments | $ | 105 | $ | 461 | $ | 119 | $ | (122 | ) | $ | 563 | $ | (15 | ) | $ | 28 | $ | 13 | |||||||||||||||||||||
| Adjusted EBITDA: | |||||||||||||||||||||||||||||||||||||||
| Northeast G&P | $ | 225 | $ | 222 | $ | 220 | $ | 219 | $ | 886 | $ | 227 | $ | 248 | $ | 475 | |||||||||||||||||||||||
| Atlantic-Gulf | 405 | 368 | 434 | 454 | 1,661 | 453 | 462 | 915 | |||||||||||||||||||||||||||||||
| West | 400 | 424 | 433 | 394 | 1,651 | 389 | 372 | 761 | |||||||||||||||||||||||||||||||
| NGL & Petchem Services | 30 | 51 | 102 | 46 | 229 | 49 | 23 | 72 | |||||||||||||||||||||||||||||||
| Other | — | — | — | — | — | (1 | ) | (1 | ) | (2 | ) | ||||||||||||||||||||||||||||
| Total Adjusted EBITDA | $ | 1,060 | $ | 1,065 | $ | 1,189 | $ | 1,113 | $ | 4,427 | $ | 1,117 | $ | 1,104 | $ | 2,221 | |||||||||||||||||||||||