Note 10 – Fair Value Measurements and Guarantees
The following table presents, by level within the fair value hierarchy, certain of our significant financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, margin deposits, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Fair Value Measurements Using |
| | Carrying Amount | | Fair Value | | Quoted Prices In Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) |
| | (Millions) |
Assets (liabilities) at March 31, 2021: | | | | | | | | | | |
Measured on a recurring basis: | | | | | | | | | | |
ARO Trust investments | | $ | 243 | | | $ | 243 | | | $ | 243 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Additional disclosures: | | | | | | | | | | |
| | | | | | | | | | |
Long-term debt, including current portion | | (23,234) | | | (26,798) | | | 0 | | | (26,798) | | | 0 | |
Guarantees | | (40) | | | (26) | | | 0 | | | (10) | | | (16) | |
| | | | | | | | | | |
Assets (liabilities) at December 31, 2020: | | | | | | | | | | |
Measured on a recurring basis: | | | | | | | | | | |
ARO Trust investments | | $ | 235 | | | $ | 235 | | | $ | 235 | | | $ | 0 | | | $ | 0 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Additional disclosures: | | | | | | | | | | |
Long-term debt, including current portion | | (22,344) | | | (27,043) | | | 0 | | | (27,043) | | | 0 | |
Guarantees | | (40) | | | (27) | | | 0 | | | (11) | | | (16) | |
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets measured at fair value on a recurring basis
ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations (ARO). The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Additional fair value disclosures
Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton lateral and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach.
Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.
To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $26 millionat March 31, 2021. Our exposure declines systematically through the remaining term of WilTel’s obligation.
The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have 0 carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
Nonrecurring fair value measurements
During the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock (NYSE: WMB), which declined 40 percent during the quarter, including a 26 percent decline in the month of March. These changes were generally attributed to macroeconomic and geopolitical conditions, including significant declines in crude oil prices driven by both surplus supply and a decrease in demand caused by the coronavirus (COVID-19) pandemic. As a result of these conditions, we performed an interim assessment of the goodwill associated with our Northeast G&P reporting unit as of March 31, 2020.
The assessment considered the total fair value of the businesses within the Northeast G&P reporting unit, which was determined using income and market approaches. We utilized internally developed industry weighted-average discount rates and estimates of valuation multiples of comparable publicly traded gathering and processing companies. In assessing the fair value as of the March 31, 2020 measurement date, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA (earnings before interest, taxes, depreciation, and amortization) market multiples as compared with recent history and significantly higher industry weighted-average discount rates. The fair value of the reporting unit was further reconciled to our estimated total enterprise value as of March 31, 2020, which considered observable valuation multiples of comparable publicly traded companies applied to each distinct business including the Northeast G&P reporting unit. This assessment indicated that the estimated fair value of the Northeast G&P reporting unit was below its carrying value, including goodwill. As a result of this Level 3 measurement, we recognized a full impairment charge of $187 million as of March 31, 2020, in Impairment of goodwill in the Consolidated Statement of Operations. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.
The following table presents impairments of equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Impairments |
| | | | | | | | Three Months Ended March 31, |
| | Segment | | Date of Measurement | | Fair Value | | 2021 | | 2020 |
| | | | | | (Millions) |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Impairment of equity-method investments: | | | | | | | | | | |
RMM (1) | | West | | March 31, 2020 | | $ | 557 | | | | | $ | 243 | |
Brazos Permian II (1) | | West | | March 31, 2020 | | 0 | | | | | 193 | |
Caiman II (2) | | Northeast G&P | | March 31, 2020 | | 191 | | | | | 229 | |
Appalachia Midstream Investments (2) | | Northeast G&P | | March 31, 2020 | | 2,700 | | | | | 127 | |
Aux Sable (2) | | Northeast G&P | | March 31, 2020 | | 7 | | | | | 39 | |
Laurel Mountain (2) | | Northeast G&P | | March 31, 2020 | | 236 | | | | | 10 | |
Discovery (2) | | Transmission & Gulf of Mexico | | March 31, 2020 | | 367 | | | | | 97 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
Impairment of equity-method investments | | | | | | | | $ | 0 | | | $ | 938 | |
_______________
(1)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the market declines previously discussed.
(2)Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in Caiman II and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments, including gathering systems that are part of Appalachia Midstream Investments, were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the market declines previously discussed.
Note 11 – Fair Value Measurements and Guarantees
The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash and cash equivalents, accounts receivable, margin deposits, and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
|
| | | | | | | | | | | | | | | | | | | | |
| | | | | | Fair Value Measurements Using |
| | Carrying Amount | | Fair Value | | Quoted Prices In Active Markets for Identical Assets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) |
| | (Millions) |
Assets (liabilities) at March 31, 2020: | | | | | | | | | | |
Measured on a recurring basis: | | | | | | | | | | |
ARO Trust investments | | $ | 188 |
| | $ | 188 |
| | $ | 188 |
| | $ | — |
| | $ | — |
|
Energy derivative assets designated as hedging instruments | | 2 |
| | 2 |
| | 2 |
| | — |
| | — |
|
Energy derivative assets not designated as hedging instruments | | 2 |
| | 2 |
| | 2 |
| | — |
| | — |
|
Energy derivative liabilities not designated as hedging instruments | | (5 | ) | | (5 | ) | | (3 | ) | | — |
| | (2 | ) |
Additional disclosures: | | | | | | | | | | |
Long-term debt, including current portion | | (22,476 | ) | | (22,531 | ) | | — |
| | (22,531 | ) | | — |
|
Guarantees | | (41 | ) | | (27 | ) | | — |
| | (11 | ) | | (16 | ) |
| | | | | | | | | | |
Assets (liabilities) at December 31, 2019: | | | | | | | | | | |
Measured on a recurring basis: | | | | | | | | | | |
ARO Trust investments | | $ | 201 |
| | $ | 201 |
| | $ | 201 |
| | $ | — |
| | $ | — |
|
Energy derivative assets not designated as hedging instruments | | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
|
Energy derivative liabilities not designated as hedging instruments | | (3 | ) | | (3 | ) | | (1 | ) | | — |
| | (2 | ) |
Additional disclosures: | | | | | | | | | | |
Long-term debt, including current portion | | (22,288 | ) | | (25,319 | ) | | — |
| | (25,319 | ) | | — |
|
Guarantees | | (41 | ) | | (27 | ) | | — |
| | (11 | ) | | (16 | ) |
Fair Value Methods
We use the following methods and assumptions in estimating the fair value of our financial instruments:
Assets and liabilities measured at fair value on a recurring basis
ARO Trust investments: Transco deposits a portion of its collected rates, pursuant to its rate case settlement, into an external trust (ARO Trust) that is specifically designated to fund future asset retirement obligations (ARO). The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market and is reported in Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities.
Energy derivatives: Energy derivatives include commodity-based exchange-traded contracts and over-the-counter contracts, which consist of physical forwards, futures, and swaps that are measured at fair value on a recurring basis.
The fair value amounts are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements. Further, the amounts do not include cash held on deposit in margin accounts that we have received or remitted to collateralize certain derivative positions. Energy derivative assets are reported in Other current assets and deferred charges and Regulatory assets, deferred charges, and other in the Consolidated Balance Sheet. Energy derivative liabilities are reported in Accrued liabilities and Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
Additional fair value disclosures
Long-term debt, including current portion: The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair values of the financing obligations associated with our Dalton lateral and Atlantic Sunrise projects, which are included within long-term debt, were determined using an income approach.
Guarantees: Guarantees primarily consist of a guarantee we have provided in the event of nonpayment by our previously owned communications subsidiary, Williams Communications Group (WilTel), on a lease performance obligation that extends through 2042. Guarantees also include an indemnification related to a disposed operation.
To estimate the fair value of the WilTel guarantee, an estimated default rate is applied to the sum of the future contractual lease payments using an income approach. The estimated default rate is determined by obtaining the average cumulative issuer-weighted corporate default rate based on the credit rating of WilTel’s current owner and the term of the underlying obligation. The default rate is published by Moody’s Investors Service. The carrying value of the WilTel guarantee is reported in Accrued liabilities in the Consolidated Balance Sheet. The maximum potential undiscounted exposure is approximately $28 millionat March 31, 2020. Our exposure declines systematically through the remaining term of WilTel’s obligation.
The fair value of the guarantee associated with the indemnification related to a disposed operation was estimated using an income approach that considered probability-weighted scenarios of potential levels of future performance. The terms of the indemnification do not limit the maximum potential future payments associated with the guarantee. The carrying value of this guarantee is reported in Regulatory liabilities, deferred income, and other in the Consolidated Balance Sheet.
We are required by our revolving credit agreement to indemnify lenders for certain taxes required to be withheld from payments due to the lenders and for certain tax payments made by the lenders. The maximum potential amount of future payments under these indemnifications is based on the related borrowings and such future payments cannot currently be determined. These indemnifications generally continue indefinitely unless limited by the underlying tax regulations and have 0 carrying value. We have never been called upon to perform under these indemnifications and have no current expectation of a future claim.
Nonrecurring fair value measurements
During the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock (NYSE: WMB), which declined 40 percent during the quarter, including a 26 percent decline in the month of March. These changes were generally attributed to recent macroeconomic and geopolitical conditions, including significant declines in crude oil prices driven by both surplus supply and a decrease in demand caused by the novel coronavirus (COVID-19) pandemic. As a result of these conditions, we performed an interim assessment of the goodwill associated with our Northeast G&P reporting unit as of March 31, 2020. This goodwill resulted from the March 2019 acquisition of UEOM (see Note 2 – Acquisitions).
The assessment considered the total fair value of the businesses within the Northeast G&P reporting unit, which were determined using income and market approaches. We utilized internally developed industry weighted-average discount rates and estimates of valuation multiples of comparable publicly traded gathering and processing companies. In assessing the fair value as of the March 31, 2020 measurement date, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA (earnings before interest, taxes,
depreciation, and amortization) market multiples as compared with recent history and significantly higher industry weighted-average discount rates. The fair value of the reporting unit was further reconciled to our estimated total enterprise value as of March 31, 2020, which considered observable valuation multiples of comparable publicly traded companies applied to each distinct business including the Northeast G&P reporting unit. This assessment indicated that the estimated fair value of the Northeast G&P reporting unit was below its carrying value, including goodwill. As a result of this Level 3 measurement, we recognized a full impairment charge of $187 million as of March 31, 2020, in Impairment of goodwill in the Consolidated Statement of Operations. Our partner’s $65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations (see Note 2 – Acquisitions).
The following table presents impairments of assets and equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy, except as specifically noted.
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| | | | | | | | | | | | | | | | |
| | | | | | | | Impairments |
| | | | | | | | Three Months Ended March 31, |
| | Segment | | Date of Measurement | | Fair Value | | 2020 | | 2019 |
| | | | | | (Millions) |
Impairment of certain assets: | | | | | | | | | | |
Certain idle gathering assets (1) | | West | | March 31, 2019 | | $ | — |
| |
| | $ | 12 |
|
Impairment of equity-method investments: | | | | | | | | | | |
RMM (2) | | West | | March 31, 2020 | | $ | 557 |
| | $ | 243 |
| | |
Brazos Permian II (2) | | West | | March 31, 2020 | | — |
| | 193 |
| | |
Caiman II (3) | | Northeast G&P | | March 31, 2020 | | 191 |
| | 229 |
| | |
Appalachia Midstream Investments (3) | | Northeast G&P | | March 31, 2020 | | 2,700 |
| | 127 |
| | |
Aux Sable (3) | | Northeast G&P | | March 31, 2020 | | 7 |
| | 39 |
| | |
Laurel Mountain (3) | | Northeast G&P | | March 31, 2020 | | 236 |
| | 10 |
| | |
Discovery (3) | | Transmission & Gulf of Mexico | | March 31, 2020 | | 367 |
| | 97 |
| | |
UEOM (4) | | Northeast G&P | | March 17, 2019 | | 1,210 |
| |
| | $ | 74 |
|
Impairment of equity-method investments | | | | | | | | $ | 938 |
| | $ | 74 |
|
_______________
| |
(1) | Reflects impairment of Property, plant, and equipment – net that is no longer in use for which the fair value was determined to be lower than the carrying value. This impairment is reported in Other (income) expense – net within Costs and expenses in the Consolidated Statement of Operations.
|
| |
(2) | Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The fair value was measured using an income approach. Both investees operate in primarily oil-driven basins where significant expected reductions in producer activities led to reduced estimates of expected future cash flows. Our fair value estimates also reflected discount rates of approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. The industry weighted-average discount rates utilized were significantly influenced by the recent market declines previously discussed. |
| |
(3) | Following the previously described declining market conditions during the first quarter of 2020, we evaluated these investments for other-than-temporary impairment. The impairments within our Northeast G&P segment are |
primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices which historically trend with crude oil prices. The fair values of our investments in Caiman II and Aux Sable Liquid Products LP (Aux Sable) were estimated using a market approach, reflecting valuation multiples ranging from 5.0x to 6.2x EBITDA (weighted-average 6.0x). The fair values of the other investments were estimated using an income approach, with discount rates ranging from 9.7 percent to 13.5 percent (weighted-average 12.6 percent). We also considered any debt held at the investee level, and its impact to fair value. The assumed valuation multiples and industry weighted-average discount rates utilized were both significantly influenced by the recent market declines previously discussed.
| |
(4) | The estimated fair value was determined by a market approach based on the transaction price for the purchase of the remaining interest in UEOM as finalized just prior to the signing and closing of the acquisition in March 2019 (see Note 2 – Acquisitions). These inputs resulted in a fair value measurement within Level 2 of the fair value hierarchy. |
Note 12 – Contingent Liabilities
Reporting of Natural Gas-Related Information to Trade Publications
Direct and indirect purchasers of natural gas in various states filed individual and class actions against us, our former affiliate WPX Energy, Inc. (WPX) and its subsidiaries, and others alleging the manipulation of published gas price indices and seeking unspecified amounts of damages. Such actions were transferred to the Nevada federal district court for consolidation of discovery and pre-trial issues. We have agreed to indemnify WPX and its subsidiaries related to this matter.
In the individual action, filed by Farmland Industries Inc. (Farmland), the court issued an order on May 24, 2016, granting one of our co-defendant’s motion for summary judgment as to Farmland’s claims. On January 5, 2017, the court extended such ruling to us, entering final judgment in our favor. Farmland appealed. On March 27, 2018, the appellate court reversed the district court’s grant of summary judgment, and on April 10, 2018, the defendants filed a petition for rehearing with the appellate court, which was denied on May 9, 2018. The case was remanded to the Nevada federal district court and subsequently has been remanded to its originally filed court, the Kansas federal district court where we re-urged our motion for summary judgment. The district court denied the motion but granted our request to seek permission for an immediate appeal to the appellate court. Oral argument occurred before the appellate court on January 19, 2021, and we await the appellate court’s ruling.
In the putative class actions, on March 30, 2017, the court issued an order denying the plaintiffs’ motions for class certification. On June 13, 2017, the United States Court of Appeals for the Ninth Circuit granted the plaintiffs’ petition for permission to appeal the order. On August 6, 2018, the Ninth Circuit reversed the order denying class certification and remanded the case to the Nevada federal district court.
We reached an agreement to settle two of the actions, and on April 22, 2019, the Nevada federal district court preliminarily approved the settlements, which are on behalf of Kansas and Missouri class members. The final fairness hearing on the settlement occurred August 5, 2019, and a final judgment of dismissal with prejudice was entered the same day.
Two putative class actions remain unresolved, and they have been remanded to their originally filed court, the Wisconsin federal district court. Trial iswas scheduled to begin June 14, 2021.2021, but the court struck the setting and has not reset it.
Because of the uncertainty around the remaining pending unresolved issues, we cannot reasonably estimate a range of potential exposure at this time. However, it is reasonably possible that the ultimate resolution of these actions and our related indemnification obligation could result in a potential loss that may be material to our results of operations. In connection with this indemnification, we have an accrued liability balance associated with this matter and, as a result, have exposure to future developments.
Alaska Refinery Contamination Litigation
We are involved in litigation arising from our ownership and operation of the North Pole Refinery in North Pole, Alaska, from 1980 until 2004, through our wholly owned subsidiaries Williams Alaska Petroleum Inc. (WAPI) and MAPCO Inc. We sold the refinery to Flint Hills Resources Alaska, LLC (FHRA), a subsidiary of Koch Industries, Inc., in 2004. The litigation involves three cases, with filing dates ranging from 2010 to 2014. The actions primarily arise
from sulfolane contamination allegedly emanating from the refinery. A putative class action lawsuit was filed by James West in 2010 naming us, WAPI, and FHRA as defendants. We and FHRA filed claims against each other seeking, among other things, contractual indemnification alleging that the other party caused the sulfolane contamination. In 2011, we and FHRA settled the claim with James West. Certain claims by FHRA against us were resolved by the Alaska Supreme Court in our favor. FHRA’s claims against us for contractual indemnification and statutory claims for damages related to off-site sulfolane were remanded to the Alaska Superior Court. The State of Alaska filed its action in March 2014, seeking damages. The City of North Pole (North Pole) filed its lawsuit in November 2014, seeking past and future damages, as well as punitive damages. Both we and WAPI asserted counterclaims against the State of Alaska and North Pole, and cross-claims against FHRA. FHRA has also filed cross-claims against us.
The underlying factual basis and claims in the cases are similar and may duplicate exposure. As such, in February 2017, the three cases were consolidated into one action in state court containing the remaining claims from the James West case and those of the State of Alaska and North Pole. The State of Alaska later announced the discovery of additional contaminants per- and polyfluoralkyl (PFOS and PFOA) offsite of the refinery, and the Courtcourt permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The Courtcourt subsequently remanded the offsite PFOS/PFOA claims to the Alaska Department of Environmental Conservation for investigation and stayed the claims pending their potential resolution at the administrative agency. Several trial dates encompassing all three cases have been scheduled and stricken. In the summer of 2019, the Court court
deconsolidated the cases for purposes of trial. A bench trial on all claims except North Pole’s claims began in October 2019.
In January 2020, the Alaska Superior Court issued its Memorandum of Decision finding in favor of the State of Alaska and FHRA, with the total incurred and potential future damages estimated to be $86 million. The Courtcourt found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the Courtcourt entered final judgment in the case. Filing deadlines have beenwere stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also expectfiled post-judgment motions including a Motion for New Trial and a Motion to file post-judgment motions.Alter or Amend the Judgment. These post-trial motions will bewere resolved beforewith the court’s denial of the last motion on June 11, 2020. Our Statement of Points on Appeal was filed on July 13, 2020. On June 22, 2020, the court stayed the North Pole’s case pending resolution of the appeal in the State of Alaska and FHRA case. On December 23, 2020, we filed our opening brief on appeal. We have recorded an accrued liability in the amount of our estimate of the probable loss. It is reasonably possible that we may not be successful on appeal and could ultimately pay up to the amount of judgment.
Royalty Matters
Certain of our customers, including one major customer,Chesapeake Energy Corporation (Chesapeake), have been named in various lawsuits alleging underpayment of royalties and claiming, among other things, violations of anti-trust laws and the Racketeer Influenced and Corrupt Organizations Act. We have also been named as a defendant in certain of these cases filed in Pennsylvania based on allegations that we improperly participated with that major customerChesapeake in causing the alleged royalty underpayments. We believe that the claims asserted are subject to indemnity obligations owed to us by that major customer. That customerChesapeake. Chesapeake has reached a tentative settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement would applyapplies to both the customerChesapeake and us. The settlement as reported woulddoes not require any contribution from us.us and is awaiting court approval.
Litigation Against Energy Transfer and Related Parties
On April 6, 2016, we filed suit in Delaware Chancery Court against Energy Transfer Equity, L.P. (Energy Transfer) and LE GP, LLC (the general partner for Energy Transfer) alleging willful and material breaches of the Agreement and Plan of Merger (ETE Merger Agreement) with Energy Transfer resulting from the private offering by Energy Transfer on March 8, 2016, of Series A Convertible Preferred Units (Special Offering) to certain Energy Transfer insiders and other accredited investors. The suit seeks, among other things, an injunction ordering the defendants to unwind the Special Offering and to specifically perform their obligations under the ETE Merger Agreement. On April 19, 2016, we filed an amended complaint seeking the same relief. On May 3, 2016, Energy Transfer and LE GP, LLC filed an answer and counterclaims.
On May 13, 2016, we filed a separate complaint in Delaware Chancery Court against Energy Transfer, LE GP, LLC and the other Energy Transfer affiliates that are parties to the ETE Merger Agreement, alleging material breaches of the ETE Merger Agreement for failing to cooperate and use necessary efforts to obtain a tax opinion required under the ETE Merger Agreement (Tax Opinion) and for otherwise failing to use necessary efforts to consummate the merger
under the ETE Merger Agreement wherein we would be merged with and into the newly formed Energy Transfer Corp LP (ETC) (ETC Merger). The suit sought, among other things, a declaratory judgment and injunction preventing Energy Transfer from terminating or otherwise avoiding its obligations under the ETE Merger Agreement due to any failure to obtain the Tax Opinion.
The Court of Chancery coordinated the Special Offering and Tax Opinion suits. On May 20, 2016, the Energy Transfer defendants filed amended affirmative defenses and verified counterclaims in the Special Offering and Tax Opinion suits, alleging certain breaches of the ETE Merger Agreement by us and seeking, among other things, a declaration that we were not entitled to specific performance, that Energy Transfer could terminate the ETC Merger, and that Energy Transfer is entitled to a $1.48 billion termination fee. On June 24, 2016, following a two-day trial, the court issued a Memorandum Opinion and Order denying our requested relief in the Tax Opinion suit. The court did not rule on the substance of our claims related to the Special Offering or on the substance of Energy Transfer’s counterclaims. On June 27, 2016, we filed an appeal of the court’s decision with the Supreme Court of Delaware, seeking reversal and remand to pursue damages. On March 23, 2017, the Supreme Court of Delaware affirmed the
Court of Chancery’s ruling. On March 30, 2017, we filed a motion for reargument with the Supreme Court of Delaware, which was denied on April 5, 2017.
On September 16, 2016, we filed an amended complaint with the Court of Chancery seeking damages for breaches of the ETE Merger Agreement by defendants. On September 23, 2016, Energy Transfer filed a second amended and supplemental affirmative defenses and verified counterclaim with the Court of Chancery seeking, among other things, payment of the $1.48 billion termination fee due to our alleged breaches of the ETE Merger Agreement. On December 1, 2017, the court granted our motion to dismiss certain of Energy Transfer’s counterclaims, including its claim seeking payment of the $1.48 billion termination fee. On December 8, 2017, Energy Transfer filed a motion for reargument, which the Court of Chancery denied on April 16, 2018. The Court of Chancery previouslyoriginally scheduled trial for May 20 through May 24, 2019; the court struck the trialthat setting and re-scheduledreset trial for June 8 through June 11 and June 15, 2020;to occur in 2020. All 2020 trial settings were struck due to COVID-19, the court struck the setting andCOVID-19. Trial has re-scheduled trial for August 31 through September 4, 2020.
Former Olefins Business
SABIC Petrochemicals, the other interest owner in our former Geismar, Louisiana, olefins facility we sold in July 2017, is seeking recovery from us for losses it allegedly suffered, including its share of personal injury settlements in which it was a co-defendant, as well as amounts related to lost income, defense costs, and property damage associated with an explosion and fire at the plant in June 2013. Due to the complexity of the various claims and available defenses, we are unable to reliably estimate any reasonably possible losses at this time. Trial began on October 14, 2019, as scheduled, but on October 21, 2019, the Court declared a mistrial due to the conduct of an officer of SABIC Petrochemicals and SABIC Petrochemicals’ expert witness. Trial is currentlybeen reset for November 4, 2020. We believe that certain losses incurred arising directly from the explosion and fire will be covered by our general liability policy and any uninsured losses are not expected to be material.
Other
On August 31, 2018, Transco submitted to the FERC a general rate filing principally designed to recover increased costs and to comply with the terms of the settlement in its prior rate proceeding. The new rates became effective March 1, 2019, subject to refund and the outcome of a hearing. In October 2019, we reached an agreement on the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing, and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of settlement. On March 24, 2020, the FERC issued an order approving the uncontested rate case settlement, which will become effective on June 1, 2020. As of March 31, 2020, we have provided a $248 million reserve for rate refunds related to increased rates collected since March 2019, which we believe is adequate for any refunds that may be required.May 10 through May 17, 2021.
Environmental Matters
We are a participant in certain environmental activities in various stages including assessment studies, cleanup operations, and/or remedial processes at certain sites, some of which we currently do not own. We are monitoring these sites in a coordinated effort with other potentially responsible parties, the U.S. Environmental Protection Agency (EPA), or other governmental authorities. We are jointly and severally liable along with unrelated third parties in some of these
activities and solely responsible in others. Certain of our subsidiaries have been identified as potentially responsible parties at various Superfund and state waste disposal sites. In addition, these subsidiaries have incurred, or are alleged to have incurred, various other hazardous materials removal or remediation obligations under environmental laws. As of March 31, 2020,2021, we have accrued liabilities totaling $30$33 million for these matters, as discussed below. Estimates of the most likely costs of cleanup are generally based on completed assessment studies, preliminary results of studies, or our experience with other similar cleanup operations. At March 31, 2020,2021, certain assessment studies were still in process for which the ultimate outcome may yield different estimates of most likely costs. Therefore, the actual costs incurred will depend on the final amount, type, and extent of contamination discovered at these sites, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.
The EPA and various state regulatory agencies routinely promulgate and propose new rules and issue updated guidance to existing rules. These rulemakings include, but are not limited to, rules for reciprocating internal combustion engine and combustion turbine maximum achievable control technology, air quality standards for one-hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. The EPA previously issued its rule regarding National Ambient Air Quality Standards for ground-level ozone. We are monitoring the rule’s implementation as it will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Property, plant, and equipment – net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance.
Continuing operations
Our interstate gas pipelines are involved in remediation activities related to certain facilities and locations for polychlorinated biphenyls, mercury, and other hazardous substances. These activities have involved the EPA and various state environmental authorities, resulting in our identification as a potentially responsible party at various Superfund waste sites. At March 31, 2020,2021, we have accrued liabilities of $4 million for these costs. We expect that these costs will be recoverable through rates.
We also accrue environmental remediation costs for natural gas underground storage facilities, primarily related to soil and groundwater contamination. At March 31, 2020,2021, we have accrued liabilities totaling $6$8 million for these costs.
Former operations
We have potential obligations in connection with assets and businesses we no longer operate. These potential obligations include remediation activities at the direction of federal and state environmental authorities and the indemnification of the purchasers of certain of these assets and businesses for environmental and other liabilities existing at the time the sale was consummated. Our responsibilities relate to the operations of the assets and businesses described below.
•Former agricultural fertilizer and chemical operations and former retail petroleum and refining operations;
•Former petroleum products and natural gas pipelines;
•Former petroleum refining facilities;
•Former exploration and production and mining operations;
•Former electricity and natural gas marketing and trading operations.
At March 31, 2020,2021, we have accrued environmental liabilities of $20$21 million related to these matters.
Other Divestiture Indemnifications
Pursuant to various purchase and sale agreements relating to divested businesses and assets, we have indemnified certain purchasers against liabilities that they may incur with respect to the businesses and assets acquired from us. The indemnities provided to the purchasers are customary in sale transactions and are contingent upon the purchasers incurring liabilities that are not otherwise recoverable from third parties. The indemnities generally relate to breach of warranties, tax, historic litigation, personal injury, property damage, environmental matters, right of way, and other representations that we have provided.
At March 31, 2020,2021, other than as previously disclosed, we are not aware of any material claims against us involving the above-described indemnities; thus, we do not expect any of the indemnities provided pursuant to the sales agreements to have a material impact on our future financial position. Any claim for indemnity brought against us in the future may have a material adverse effect on our results of operations in the period in which the claim is made.
In addition to the foregoing, various other proceedings are pending against us whichthat are incidental to our operations, none of which are expected to be material to our expected future annual results of operations, liquidity, and financial position.
Summary
We have disclosed our estimated range of reasonably possible losses for certain matters above, as well as all significant matters for which we are unable to reasonably estimate a range of possible loss. We estimate that for all other matters for which we are able to reasonably estimate a range of loss, our aggregate reasonably possible losses beyond amounts accrued are immaterial to our expected future annual results of operations, liquidity, and financial position. These calculations have been made without consideration of any potential recovery from third parties.
Note 12 – Segment Disclosures
Our reportable segments are Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities are included in Other. (See Note 1 – General, Description of Business, and Basis of Presentation.)
Performance Measurement
We evaluate segment operating performance based upon Modified EBITDA. This measure represents the basis of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment revenues
primarily represent the sale of NGLs from our natural gas processing plants and transportation services provided to our marketing business.
We define Modified EBITDA as follows:
•Net income (loss) before:
◦Provision (benefit) for income taxes;
◦Interest incurred, net of interest capitalized;
◦Equity earnings (losses);
◦Impairment of equity-method investments;
◦Other investing income (loss) – net;
◦Impairment of goodwill;
◦Depreciation and amortization expenses;
◦Accretion expense associated with asset retirement obligations for nonregulated operations.
•This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above.
The following table reflects the reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Operations and Total assets by reportable segment.
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| Transmission & Gulf of Mexico | | Northeast G&P | | West | | Other | | Eliminations | | Total |
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Three Months Ended March 31, 2021 |
Segment revenues: | | | | | | | | | | | |
Service revenues | | | | | | | | | | | |
External | $ | 822 | | | $ | 347 | | | $ | 279 | | | $ | 4 | | | $ | — | | | $ | 1,452 | |
Internal | 12 | | | 11 | | | 5 | | | 3 | | | (31) | | | — | |
Total service revenues | 834 | | | 358 | | | 284 | | | 7 | | | (31) | | | 1,452 | |
Total service revenues – commodity consideration | 11 | | | 3 | | | 35 | | | 0 | | | 0 | | | 49 | |
Product sales | | | | | | | | | | | |
External | 40 | | | 4 | | | 1,018 | | | 49 | | | — | | | 1,111 | |
Internal | 27 | | | 28 | | | 28 | | | 7 | | | (90) | | | — | |
Total product sales | 67 | | | 32 | | | 1,046 | | | 56 | | | (90) | | | 1,111 | |
Total revenues | $ | 912 | | | $ | 393 | | | $ | 1,365 | | | $ | 63 | | | $ | (121) | | | $ | 2,612 | |
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Three Months Ended March 31, 2020 |
Segment revenues: | | | | | | | | | | | |
Service revenues | | | | | | | | | | | |
External | $ | 814 | | | $ | 344 | | | $ | 311 | | | $ | 5 | | | $ | — | | | $ | 1,474 | |
Internal | 15 | | | 14 | | | 0 | | | 3 | | | (32) | | | — | |
Total service revenues | 829 | | | 358 | | | 311 | | | 8 | | | (32) | | | 1,474 | |
Total service revenues – commodity consideration | 5 | | | 2 | | | 21 | | | 0 | | | 0 | | | 28 | |
Product sales | | | | | | | | | | | |
External | 41 | | | 23 | | | 347 | | | 0 | | | — | | | 411 | |
Internal | 11 | | | 6 | | | 12 | | | 0 | | | (29) | | | — | |
Total product sales | 52 | | | 29 | | | 359 | | | 0 | | | (29) | | | 411 | |
Total revenues | $ | 886 | | | $ | 389 | | | $ | 691 | | | $ | 8 | | | $ | (61) | | | $ | 1,913 | |
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March 31, 2021 | | | | | | | | | | | |
Total assets (1) | $ | 19,395 | | | $ | 14,464 | | | $ | 10,533 | | | $ | 2,225 | | | $ | (1,355) | | | $ | 45,262 | |
December 31, 2020 | | | | | | | | | | | |
Total assets | $ | 19,110 | | | $ | 14,569 | | | $ | 10,558 | | | $ | 927 | | | $ | (999) | | | $ | 44,165 | |
______________
(1) The increase at our Other segment is primarily due to increased cash balance and the February 2021 acquisition of oil and gas properties, primarily comprised of approximately 2,000 operated wells, in the Wamsutter basin in Wyoming from a supermajor oil and gas company for approximately $79 million, a portion of which was paid in the prior year. We are working to identify an operating partner to optimize development of the properties and enhance the value of our connected midstream infrastructure. Our oil and gas exploration and production activities are accounted for under the successful efforts method. We recorded $290 million of property, plant, and equipment and $207 million of ARO related to this transaction.
The following table reflects the reconciliation of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Operations.
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| | | | | 2021 | | 2020 |
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Modified EBITDA by segment: | | | | | | | |
Transmission & Gulf of Mexico | | | | | $ | 660 | | | $ | 662 | |
Northeast G&P | | | | | 402 | | | 369 | |
West | | | | | 315 | | | 215 | |
Other | | | | | 33 | | | 7 | |
| | | | | 1,410 | | | 1,253 | |
Accretion expense associated with asset retirement obligations for nonregulated operations | | | | | (10) | | | (10) | |
Depreciation and amortization expenses | | | | | (438) | | | (429) | |
Impairment of goodwill | | | | | 0 | | | (187) | |
Equity earnings (losses) | | | | | 131 | | | 22 | |
Impairment of equity-method investments | | | | | 0 | | | (938) | |
Other investing income (loss) – net | | | | | 2 | | | 3 | |
Proportional Modified EBITDA of equity-method investments | | | | | (225) | | | (192) | |
Interest expense | | | | | (294) | | | (296) | |
(Provision) benefit for income taxes | | | | | (141) | | | 204 | |
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Net income (loss) | | | | | $ | 435 | | | $ | (570) | |
Note 13 – Segment DisclosuresItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs through our gas pipeline and midstream business. Our operations are located in the United States.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. Rates are established in accordance with the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.
Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments aresegments: Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities, including our recently acquired upstream operations, as well as corporate activities are included in Other. (SeeOur reportable segments are comprised of the following businesses:
•Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, as well as 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 VIE), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.
•Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania and New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated VIE) which operates in Ohio, a 69 percent equity-method investment in Laurel Mountain, a 50 percent equity-method investment in Blue Racer (we previously effectively owned a 29 percent indirect interest in Blue Racer through our 58 percent equity-method investment in Caiman II until acquiring a controlling interest in November 2020), and Appalachia Midstream Investments, a wholly owned subsidiary that owns equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale region.
•West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, 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, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, a 20 percent equity-method investment in Targa Train 7, and a 15 percent interest in Brazos Permian II.
Management’s Discussion and Analysis (Continued)
Dividends
In March 2021, we paid a regular quarterly dividend of $0.41 per share.
Overview of Three Months Ended March 31, 2021
Net income (loss) attributable to The Williams Companies, Inc., for the three months ended March 31, 2021, increased $943 millioncompared to the three months ended March 31, 2020, reflecting:
•The absence of $938 million of Impairment of equity-method investments in the first quarter of 2020;
•The absence of $187 million of Impairment of goodwill in 2020, of which $65 million was attributable to noncontrolling interests;
•A $128 million favorable change in our commodity margins primarily due to increases in net realized sales prices and volumes. Our commodity margins are comprised of the net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses; however, Product sales at our Other segment reflect sales related to our recently acquired upstream operations and are excluded from our commodity margins;
•A $109 million increase in equity earnings, primarily due to the absence of our $78 million share of an impairment of goodwill recorded by an equity-method investee in 2020;
•A $49 million increase in Product sales at our Other segment reflecting sales related to our recently acquired upstream operations.
These favorable changes were partially offset by:
•A $345 million unfavorable change in provision for income taxes, driven by higher pre-tax earnings;
•$23 million of higher Operating and maintenance expenses primarily due to the inclusion of our recently acquired upstream operations at our Other segment and higher employee-related expenses;
•$22 million of lower Service revenues primarily due to lower volumes and rates.
The following discussion and analysis of results of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our Annual Report on Form 10-K dated February 24, 2021.
Recent Developments
Expansion Project Update
Transmission & Gulf of Mexico
Southeastern Trail
In October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We placed 230 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and the project was fully in service on January 1, 2021. In total, the project increased capacity by 296 Mdth/d.
COVID-19
The outbreak of COVID-19 has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We continue to monitor the COVID-19 pandemic and have taken steps intended to protect the safety of our customers, employees, and communities, and to support the continued delivery
Management’s Discussion and Analysis (Continued)
of safe and reliable service to our customers and the communities we serve. Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.
Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders. Our business plan for 2021 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs.
In 2021, our operating results are expected to benefit from growth in our Northeast G&P gathering and processing volumes. We also anticipate increases from recently completed Transco expansion projects and higher Gulf of Mexico results primarily due to lower planned hurricane impacts. Our results also benefited from the overall net favorable impact of unusually high natural gas prices in the first quarter, including contributions from certain of our recently acquired upstream properties. These increases will be partially offset by a decrease in West results, including a reduction in NGL transportation volumes on OPPL and certain fee reductions in the Haynesville area in exchange for upstream value in natural gas properties. We also expect a modest increase in expenses, including higher operating taxes.
Our growth capital and investment expenditures in 2021 are expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and projects supporting the Northeast G&P business and opportunities in the Haynesville area. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
Potential risks and obstacles that could impact the execution of our plan include:
•Continued negative impacts of COVID-19 driving a global recession, which could result in further downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;
•Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
•Counterparty credit and performance risk, including unexpected developments in customer bankruptcy proceedings;
•Unexpected significant increases in capital expenditures or delays in capital project execution;
•Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;
•Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;
•General economic, financial markets, or further industry downturns, including increased interest rates;
•Physical damages to facilities, including damage to offshore facilities by weather-related events;
•Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020, as filed with the SEC on February 24, 2021.
Management’s Discussion and Analysis (Continued)
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets that continue to serve key growth markets and supply basins in the United States.
Expansion Projects
Our ongoing major expansion projects include the following:
Transmission & Gulf of Mexico
Leidy South
In July 2020, we received approval from the FERC for the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We placed 125 Mdth/d of capacity under the project into service in the fourth quarter of 2020, and we plan to place the remainder of the project into service as early as the fourth quarter of 2021. The project is expected to increase capacity by 582 Mdth/d.
Regional Energy Access
In March 2021, we filed an application with the FERC for the project to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from receipt points in northeastern Pennsylvania to multiple delivery points in Pennsylvania, New Jersey, and Maryland. We plan to place the project into service as early as the fourth quarter of 2023, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 829 Mdth/d.
Management’s Discussion and Analysis (Continued)
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2021, compared to the three months ended March 31, 2020. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
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| | | | | | | Three Months Ended March 31, | | | | |
| | | | | | | | | 2021 | | 2020 | | $ Change* | | % Change* |
| | | | | | | (Millions) | | | | |
Revenues: | | | | | | | | | | | | | | | |
Service revenues | | | | | | | | | $ | 1,452 | | | $ | 1,474 | | | -22 | | | -1 | % |
Service revenues – commodity consideration | | | | | | | | | 49 | | | 28 | | | +21 | | | +75 | % |
Product sales | | | | | | | | | 1,111 | | | 411 | | | +700 | | | +170 | % |
Total revenues | | | | | | | | | 2,612 | | | 1,913 | | | | | |
Costs and expenses: | | | | | | | | | | | | | | | |
Product costs | | | | | | | | | 932 | | | 396 | | | -536 | | | -135 | % |
Processing commodity expenses | | | | | | | | | 21 | | | 13 | | | -8 | | | -62 | % |
Operating and maintenance expenses | | | | | | | | | 360 | | | 337 | | | -23 | | | -7 | % |
Depreciation and amortization expenses | | | | | | | | | 438 | | | 429 | | | -9 | | | -2 | % |
Selling, general, and administrative expenses | | | | | | | | | 123 | | | 113 | | | -10 | | | -9 | % |
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Impairment of goodwill | | | | | | | | | — | | | 187 | | | +187 | | | +100 | % |
Other (income) expense – net | | | | | | | | | (1) | | | 7 | | | +8 | | | NM |
Total costs and expenses | | | | | | | | | 1,873 | | | 1,482 | | | | | |
Operating income (loss) | | | | | | | | | 739 | | | 431 | | | | | |
Equity earnings (losses) | | | | | | | | | 131 | | | 22 | | | +109 | | | NM |
Impairment of equity-method investments | | | | | | | | | — | | | (938) | | | +938 | | | +100 | % |
Other investing income (loss) – net | | | | | | | | | 2 | | | 3 | | | -1 | | | -33 | % |
Interest expense | | | | | | | | | (294) | | | (296) | | | +2 | | | +1 | % |
Other income (expense) – net | | | | | | | | | (2) | | | 4 | | | -6 | | | NM |
Income (loss) before income taxes | | | | | | | | | 576 | | | (774) | | | | | |
Less: Provision (benefit) for income taxes | | | | | | | | | 141 | | | (204) | | | -345 | | | NM |
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Net income (loss) | | | | | | | | | 435 | | | (570) | | | | | |
Less: Net income (loss) attributable to noncontrolling interests | | | | | | | | | 9 | | | (53) | | | -62 | | | NM |
Net income (loss) attributable to The Williams Companies, Inc. | | | | | | | | | $ | 426 | | | $ | (517) | | | | | |
* + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200.
Three months ended March 31, 2021 vs. three months ended March 31, 2020
Service revenues decreased primarily due to lower volumes driven by production declines and lower gathering and processing rates, both in our West segment, as well as producer operational issues at certain offshore Gulf of Mexico operations. This decrease was partially offset by higher MVC revenue in our West segment and higher transportation fee revenues associated with expansion projects placed in service at Transco in 2020.
Service revenues – commodity consideration increased primarily due to higher NGL prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold during the month processed and therefore are offset within Product costs below.
Management’s Discussion and Analysis (Continued)
Product sales increased primarily due to higher net realized prices and higher volumes associated with our marketing activities, and the inclusion of our recently acquired upstream operations (see Note 112 – General, DescriptionSegment Disclosures of Business,Notes to Consolidated Financial Statements). This increase also includes higher prices related to our equity NGL sales activities. Marketing sales are partially offset within Product costs.
Product costs increased primarily due to higher prices and Basishigher volumes for our marketing activities, as well as higher NGL prices associated with volumes acquired related to our equity NGL production activities.
The net sum of Presentation.)Service revenues – commodity consideration, Product sales, Product costs and Processing commodity expenses comprise our commodity margins. However, Product sales at our Other segment reflect sales related to our oil and gas producing properties and are excluded from our commodity margins.
Performance MeasurementOperating and maintenance expenses increased primarily due to the inclusion of our recently acquired upstream operations and higher employee-related expenses.
Selling, general, and administrative expenses increased primarily due to higher employee-related expenses.
Impairment of goodwill reflects the 2020 charge at the Northeast reporting unit (see Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
Equity earnings (losses) changed favorably primarily due to the absence of the 2020 impairment of goodwill at RMM and due to an increase at Appalachia Midstream Investments, partially offset by a decrease at OPPL.
The change in Impairment of equity-method investments reflects the absence of 2020 impairments to various equity-method investments (see Note 10 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
Provision (benefit) for income taxes changed unfavorably primarily due to higher pre-tax income. See Note 5 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The unfavorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the absence of our partner’s share of the 2020 goodwill impairment at the Northeast reporting unit.
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. This measure represents the basisNote 12 – Segment Disclosures of our internal financial reporting and is the primary performance measure used by our chief operating decision maker in measuring performance and allocating resources among our reportable segments. Intersegment revenues primarily represent the sale of NGLs from our natural gas processing plantsNotes to our marketing business.
We define Modified EBITDA as follows:
•Net income (loss) before:
◦Provision (benefit) for income taxes;
◦Interest incurred, net of interest capitalized;
◦Equity earnings (losses);
◦Impairment of equity-method investments;
◦Other investing income (loss) – net;
◦Impairment of goodwill;
◦Depreciation and amortization expenses;
◦Accretion expense associated with asset retirement obligations for nonregulated operations.
| |
• | This measure is further adjusted to include our proportionate share (based on ownership interest) of Modified EBITDA from our equity-method investments calculated consistently with the definition described above.
|
The following table reflects theConsolidated Financial Statements includes a reconciliation of Segment revenues to Total revenues as reported in the Consolidated Statement of Operations and Total assets by reportable segment.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Transmission & Gulf of Mexico | | Northeast G&P | | West | | Other | | Eliminations | | Total |
| | | (Millions) |
Three Months Ended March 31, 2020 |
Segment revenues: | | | | | | | | | | | |
Service revenues | | | | | | | | | | | |
External | $ | 814 |
| | $ | 344 |
| | $ | 311 |
| | $ | 5 |
| | $ | — |
| | $ | 1,474 |
|
Internal | 15 |
| | 14 |
| | — |
| | 3 |
| | (32 | ) | | — |
|
Total service revenues | 829 |
| | 358 |
| | 311 |
| | 8 |
| | (32 | ) | | 1,474 |
|
Total service revenues – commodity consideration | 5 |
| | 2 |
| | 21 |
| | — |
| | — |
| | 28 |
|
Product sales | | | | | | | | | | | |
External | 41 |
| | 23 |
| | 347 |
| | — |
| | — |
| | 411 |
|
Internal | 11 |
| | 6 |
| | 12 |
| | — |
| | (29 | ) | | — |
|
Total product sales | 52 |
| | 29 |
| | 359 |
| | — |
| | (29 | ) | | 411 |
|
Total revenues | $ | 886 |
| | $ | 389 |
| | $ | 691 |
| | $ | 8 |
| | $ | (61 | ) | | $ | 1,913 |
|
| | | | | | | | | | | |
| | | | | | | | | | | |
Three Months Ended March 31, 2019 |
Segment revenues: | | | | | | | | | | | |
Service revenues | | | | | | | | | | | |
External | $ | 811 |
| | $ | 266 |
| | $ | 359 |
| | $ | 4 |
| | $ | — |
| | $ | 1,440 |
|
Internal | 12 |
| | 10 |
| | — |
| | 3 |
| | (25 | ) | | — |
|
Total service revenues | 823 |
| | 276 |
| | 359 |
| | 7 |
| | (25 | ) | | 1,440 |
|
Total service revenues – commodity consideration | 13 |
| | 5 |
| | 46 |
| | — |
| | — |
| | 64 |
|
Product sales | | | | | | | | | | | |
External | 52 |
| | 36 |
| | 462 |
| | — |
| | — |
| | 550 |
|
Internal | 30 |
| | 11 |
| | 17 |
| | — |
| | (58 | ) | | — |
|
Total product sales | 82 |
| | 47 |
| | 479 |
| | — |
| | (58 | ) | | 550 |
|
Total revenues | $ | 918 |
| | $ | 328 |
| | $ | 884 |
| | $ | 7 |
| | $ | (83 | ) | | $ | 2,054 |
|
| | | | | | | | | | | |
March 31, 2020 | | | | | | | | | | | |
Total assets | $ | 18,656 |
| | $ | 14,702 |
| | $ | 10,619 |
| | $ | 1,309 |
| | $ | (657 | ) | | $ | 44,629 |
|
December 31, 2019 | | | | | | | | | | | |
Total assets | $ | 18,796 |
| | $ | 15,399 |
| | $ | 11,265 |
| | $ | 1,151 |
| | $ | (571 | ) | | $ | 46,040 |
|
The following table reflects the reconciliation of Modified EBITDAthis non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as reporteda substitute for a measure of performance prepared in accordance with GAAP.
Management’s Discussion and Analysis (Continued)
Transmission & Gulf of Mexico
| | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | (Millions) |
Service revenues | | | | | $ | 834 | | | $ | 829 | |
Service revenues – commodity consideration | | | | | 11 | | | 5 | |
Product sales | | | | | 67 | | | 52 | |
Segment revenues | | | | | 912 | | | 886 | |
| | | | | | | |
Product costs | | | | | (66) | | | (52) | |
Processing commodity expenses | | | | | (4) | | | (2) | |
Other segment costs and expenses | | | | | (229) | | | (214) | |
| | | | | | | |
Proportional Modified EBITDA of equity-method investments | | | | | 47 | | | 44 | |
Transmission & Gulf of Mexico Modified EBITDA | | | | | $ | 660 | | | $ | 662 | |
| | | | | | | |
Commodity margins | | | | | $ | 8 | | | $ | 3 | |
Three months ended March 31, 2021 vs. three months ended March 31, 2020
Transmission & Gulf of Mexico Modified EBITDA decreased primarily due to unfavorable changes to Other segment costs and expenses, partially offset by higher Commodity margins and Service revenues.
Service revenues increased primarily due to:
•A $17 million increase in Transco’s natural gas transportation revenues primarily associated with expansion projects placed in service in 2020, partially offset by one less billing day;
•A $10 million increase associated with Norphlet; partially offset by
•An $18 million decrease due to lower volumes primarily from certain Gulf of Mexico operations due to producer operational issues.
The increase in Product sales includes a $12 million increase in commodity marketing sales primarily due to higher NGL prices. Marketing sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.
Other segment costs and expenses increased primarily due to higher employee-related costs.
Management’s Discussion and Analysis (Continued)
Northeast G&P
| | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | (Millions) |
Service revenues | | | | | $ | 358 | | | $ | 358 | |
Service revenues – commodity consideration | | | | | 3 | | | 2 | |
Product sales | | | | | 32 | | | 29 | |
Segment revenues | | | | | 393 | | | 389 | |
| | | | | | | |
Product costs | | | | | (32) | | | (29) | |
Processing commodity expenses | | | | | — | | | (1) | |
Other segment costs and expenses | | | | | (112) | | | (110) | |
| | | | | | | |
Proportional Modified EBITDA of equity-method investments | | | | | 153 | | | 120 | |
Northeast G&P Modified EBITDA | | | | | $ | 402 | | | $ | 369 | |
| | | | | | | |
Commodity margins | | | | | $ | 3 | | | $ | 1 | |
Three months ended March 31, 2021 vs. three months ended March 31, 2020
Northeast G&P Modified EBITDA increased primarily due to increased Proportional Modified EBITDA of equity-method investments.
Product sales increased slightly primarily due to higher sales prices of NGLs associated with our marketing activities, which were substantially offset by lower sales volumes. Marketing sales are offset by similar changes in marketing purchases, reflected above as Product costs, and therefore have little impact to Modified EBITDA.
Proportional Modified EBITDA of equity-method investments increased at Appalachia Midstream Investments primarily driven by higher volumes. Additionally, there was an increase at Blue Racer/Caiman II due to the favorable impact of increased ownership, partially offset by lower volumes.
West
| | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | (Millions) |
Service revenues | | | | | $ | 284 | | | $ | 311 | |
Service revenues – commodity consideration | | | | | 35 | | | 21 | |
Product sales | | | | | 1,046 | | | 359 | |
Segment revenues | | | | | 1,365 | | | 691 | |
| | | | | | | |
Product costs | | | | | (936) | | | (368) | |
Processing commodity expenses | | | | | (17) | | | (10) | |
Other segment costs and expenses | | | | | (122) | | | (126) | |
| | | | | | | |
Proportional Modified EBITDA of equity-method investments | | | | | 25 | | | 28 | |
West Modified EBITDA | | | | | $ | 315 | | | $ | 215 | |
| | | | | | | |
Commodity margins | | | | | $ | 128 | | | $ | 2 | |
Management’s Discussion and Analysis (Continued)
Three months ended March 31, 2021 vs. three months ended March 31, 2020
West Modified EBITDA increased primarily due to higher Commodity margins, partially offset by lower Service revenues.
Service revenues decreased primarily due to:
•A $26 million decrease associated with lower gathering and processing rates, primarily in the Haynesville Shale region due to a customer contract change and in the Piceance region driven primarily by unfavorable commodity pricing;
•An $11 million decrease associated with lower volumes, primarily due to production declines in the Haynesville Shale region. The impact of lower gathering volumes in the Eagle Ford Shale region was substantially offset by the recognition of higher MVC revenue;
•A $10 million decrease related to lower deferred revenue amortization primarily in the Barnett Shale region; partially offset by
•A $10 million increase associated with higher MVC revenue, primarily in the Wamsutter region due to timing of recognition;
•A $10 million increase in revenues associated primarily with reimbursable compressor power and fuel purchases due to higher prices related to the impact of severe winter weather, which are offset by similar changes in Other segment costs and expenses.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins, which we further segregate into product margins associated with our marketing and equity NGLs margins. Marketing margins increased by $122 million primarily due to favorable changes in net realized commodity prices, including the impact of severe winter weather in the first quarter of 2021. Product margins from our equity NGLs increased $4 million, primarily due to higher net realized sales prices.
Other segment costs and expenses decreased primarily due to lower operating expenses including costs related to fewer leased compressors. These decreases are partially offset by higher reimbursable compressor power and fuel purchases which are offset in Service revenues.
Proportional Modified EBITDA of equity-method investments decreased primarily due to lower volumes at OPPL, partially offset by improvements at other equity-method investees.
Other
| | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, |
| | | | | 2021 | | 2020 |
| | | | | (Millions) |
Other Modified EBITDA | | | | | $ | 33 | | | $ | 7 | |
Three months ended March 31, 2021 vs. three months ended March 31, 2020
Other Modified EBITDA increased primarily due to our recently acquired upstream operations, including the favorable commodity price impact of severe winter weather in the first quarter of 2021. See Note 12 – Segment Disclosures of Notes to Consolidated StatementFinancial Statements.
Management’s Discussion and Analysis (Continued)
Management’s Discussion and Analysis of OperationsFinancial Condition and Liquidity
Outlook
As previously discussed in Company Outlook, our growth capital and investment expenditures in 2021 are currently expected to be in a range from $1.0 billion to $1.2 billion. Growth capital spending in 2021 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and projects supporting the Northeast G&P business and opportunities in the Haynesville area. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all of our planned 2021 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.
During the first quarter of 2021, we issued $900 million of new long-term debt to fund the repayment of long-term debt maturing in 2021 and for general corporate purposes. As of March 31, 2021, we have approximately $2.1 billion of long-term debt due within one year. Our potential sources of liquidity available to address these maturities include cash on hand, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2021. Our potential material internal and external sources and uses of liquidity are as follows:
| | | | | |
Sources: | |
| Cash and cash equivalents on hand |
| Cash generated from operations |
| Distributions from our equity-method investees |
| Utilization of our credit facility and/or commercial paper program |
| Cash proceeds from issuance of debt and/or equity securities |
| Proceeds from asset monetizations |
| |
Uses: | |
| Working capital requirements |
| Capital and investment expenditures |
| Product costs |
| Other operating costs including human capital expenses |
| Quarterly dividends to our shareholders |
| Debt service payments, including payments of long-term debt |
| Distributions to noncontrolling interests |
As of March 31, 2021, we have approximately $21.1 billion of long-term debt due after one year. Our potential sources of liquidity available to address these maturities include cash generated from operations, proceeds from refinancing at attractive long-term rates or from our credit facility, as well as proceeds from asset monetizations.
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
|
| | | | | | | |
| Three Months Ended March 31, |
| 2020 | | 2019 |
| (Millions) |
Modified EBITDA by segment: | | | |
Transmission & Gulf of Mexico | $ | 662 |
| | $ | 636 |
|
Northeast G&P | 369 |
| | 299 |
|
West | 215 |
| | 256 |
|
Other | 7 |
| | (4 | ) |
| 1,253 |
| | 1,187 |
|
Accretion expense associated with asset retirement obligations for nonregulated operations | (10 | ) | | (9 | ) |
Depreciation and amortization expenses | (429 | ) | | (416 | ) |
Impairment of goodwill | (187 | ) | | — |
|
Equity earnings (losses) | 22 |
| | 80 |
|
Impairment of equity-method investments | (938 | ) | | (74 | ) |
Other investing income (loss) – net | 3 |
| | 1 |
|
Proportional Modified EBITDA of equity-method investments | (192 | ) | | (190 | ) |
Interest expense | (296 | ) | | (296 | ) |
(Provision) benefit for income taxes | 204 |
| | (69 | ) |
Net income (loss) | $ | (570 | ) | | $ | 214 |
|
39
Management’s Discussion and Analysis (Continued)
As of March 31, 2021, we had a working capital deficit of $1.038 billion, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:
| | | | | |
Available Liquidity | March 31, 2021 |
| (Millions) |
Cash and cash equivalents | $ | 1,126 | |
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1) | 4,500 | |
| $ | 5,626 | |
(1)In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of March 31, 2021. Through March 31, 2021, there was no amount outstanding under our commercial paper program and credit facility during 2021. At March 31, 2021, we were in compliance with the financial covenants associated with our credit facility.
Dividends
We increased our regular quarterly cash dividend to common stockholders by approximately 2.5 percent from the $0.40 per share paid in each quarter of 2020, to $0.41 per share paid in March 2021.
Registrations
In February 2021, we filed a shelf registration statement as a well-known seasoned issuer.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require periodic distributions of their available cash to their members. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.
Credit Ratings
The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:
| | | | | | | | | | | | | | |
Rating Agency | | Outlook | | Senior Unsecured Debt Rating |
S&P Global Ratings | | Stable | | BBB |
Moody’s Investors Service | | Positive | | Baa3 |
Fitch Ratings | | Stable | | BBB |
These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.
Management’s Discussion and Analysis (Continued)
Sources (Uses) of Cash
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
| | | | | | | | | | | | | | | | | |
| Cash Flow | | Three Months Ended March 31, |
| Category | | 2021 | | 2020 |
| | | (Millions) |
Sources of cash and cash equivalents: | | | | | |
Operating activities – net | Operating | | $ | 915 | | | $ | 787 | |
Proceeds from long-term debt (see Note 8) | Financing | | 897 | | | 2 | |
Proceeds from credit-facility borrowings | Financing | | — | | | 1,700 | |
| | | | | |
Uses of cash and cash equivalents: | | | | | |
Common dividends paid | Financing | | (498) | | | (485) | |
Capital expenditures | Investing | | (260) | | | (306) | |
Dividends and distributions paid to noncontrolling interests | Financing | | (54) | | | (44) | |
Purchases of and contributions to equity-method investments | Investing | | (14) | | | (30) | |
Payments of long-term debt | Financing | | (5) | | | (1,518) | |
| | | | | |
Other sources / (uses) – net | Financing and Investing | | 3 | | | 5 | |
Increase (decrease) in cash and cash equivalents | | | $ | 984 | | | $ | 111 | |
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Impairment of goodwill, and Impairment of equity-method investments. Our Net cash provided (used) by operating activities for the three months ended March 31, 2021, increased from the same period in 2020 primarily due to higher operating income (excluding noncash items as previously discussed) in 2021.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
General
We are an energy infrastructure company focused on connecting North America’s significant hydrocarbon resource plays to growing markets for natural gas and NGLs through our gas pipeline and midstream business. Our operations are located in the United States.
Our interstate natural gas pipeline strategy is to create value by maximizing the utilization of our pipeline capacity by providing high quality, low cost transportation of natural gas to large and growing markets. Our gas pipeline businesses’ interstate transmission and storage activities are subject to regulation by the FERC and as such, our rates and charges for the transportation of natural gas in interstate commerce, and the extension, expansion or abandonment of jurisdictional facilities and accounting, among other things, are subject to regulation. The rates are established through the FERC’s ratemaking process. Changes in commodity prices and volumes transported have limited near-term impact on these revenues because the majority of cost of service is recovered through firm capacity reservation charges in transportation rates.
The ongoing strategy of our midstream operations is to safely and reliably operate large-scale midstream infrastructure where our assets can be fully utilized and drive low per-unit costs. We focus on consistently attracting new business by providing highly reliable service to our customers. These services include natural gas gathering, processing, treating, and compression, NGL fractionation and transportation, crude oil production handling and transportation, marketing services for NGL, crude oil and natural gas, as well as storage facilities.
Effective January 1, 2020, following an organizational realignment, our interstate natural gas pipeline Northwest Pipeline, which was reported within the West reporting segment throughout 2019, is now managed within the Transmission & Gulf of Mexico reporting segment (previously identified as the Atlantic-Gulf reporting segment). Consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources, our operations are conducted, managed, and presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West. All remaining business activities as well as corporate activities are included in Other. Our reportable segments are comprised of the following businesses:
Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transco and Northwest Pipeline, as well as 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 variable interest entity), which is a proprietary floating production system, a 50 percent equity-method investment in Gulfstream, and a 60 percent equity-method investment in Discovery.
Northeast G&P is comprised of our midstream gathering, processing, and fractionation businesses in the Marcellus Shale region primarily in Pennsylvania, New York, and the Utica Shale region of eastern Ohio, as well as a 65 percent interest in our Northeast JV (a consolidated variable interest entity) which operates in West Virginia, Ohio, and Pennsylvania, a 66 percent interest in Cardinal (a consolidated variable interest entity) which operates in Ohio, 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 equity-method investments with an approximate average 66 percent interest in multiple gas gathering systems in the Marcellus Shale (Appalachia Midstream Investments).
West is comprised of our gas gathering, processing, and treating operations in the Rocky Mountain region of Colorado and Wyoming, 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, and Permian basins. This segment also includes our NGL and natural gas marketing business, storage facilities, an undivided 50 percent interest in an NGL fractionator near Conway, Kansas, a 50 percent equity-method investment in OPPL, a 50 percent equity-method investment in RMM, and a 15 percent equity-method investment in Brazos Permian II. West also included our former 50 percent equity-method investment in Jackalope, which was sold in April 2019.
Other includes minor business activities that are not operating segments, as well as corporate operations.
Management’s Discussion and Analysis (Continued)
Dividends
In March 2020, we paid a regular quarterly dividend of $0.40 per share.
Overview of Three Months Ended March 31, 2020
Net income (loss) attributable to The Williams Companies, Inc., for the three months ended March 31, 2020, decreased $712 millioncompared to the three months ended March 31, 2019, reflecting:
| |
• | An increase of $864 million of Impairment of equity-method investments;
|
| |
• | $187 million of Impairment of goodwill;
|
A $58 million decrease in equity earnings, primarily due to our share of an impairment of goodwill recorded by an equity method investee;
$19 million of lower commodity margins.
These unfavorable changes were partially offset by:
| |
• | $34 million of increased Service revenues;
|
| |
• | $15 million of lower Selling, general, and administrative expenses;
|
| |
• | A $72 million favorable change in Net income (loss) attributable to noncontrolling interests primarily due to the noncontrolling interests’ share of the goodwill impairment;
|
A $273 million decrease in provision for income taxes driven by lower pre-tax income.
The following discussion and analysis ofresults of operations and financial condition and liquidity should be read in conjunction with the consolidated financial statements and notes thereto of this Form 10‑Q and our Annual Report on Form 10-K dated February 24, 2020.
Recent Developments
COVID-19
The outbreak of novel coronavirus (COVID-19) has severely impacted global economic activity and caused significant volatility and negative pressure in financial markets. We are monitoring the COVID-19 pandemic and are taking steps intended to protect the safety of our customers, employees and communities, and to support the continued delivery of safe and reliable service to our customers and the communities we serve. We are continuing to monitor developments with respect to the outbreak and note the following:
Our financial condition, results of operations, and liquidity have not been materially impacted by direct effects of COVID-19.
We believe we have the ability to access the debt market, if necessary, and continue to have significant levels of unused capacity on our revolving credit facility.
We have implemented remote working arrangements where possible and restricted business-related travel. Implementation of these measures has not required material expenditures or significantly impacted our ability to operate our business.
Our remote working arrangements have not significantly impacted our internal controls over financial reporting and disclosure controls and procedures.
Management’s Discussion and Analysis (Continued)
Crude Oil Price Decline
In recent months, crude oil prices have decreased as a result of surplus supply and weakened demand caused by the COVID-19 pandemic. In addition, in early March, Saudi Arabia announced that it would cut export prices and increase production, contributing to a sharp decline in crude oil prices. The significant decline in crude oil prices has also impacted NGL prices. While our businesses do not have direct exposure to crude oil prices, the combined impacts of the crude oil price decline on our industry and the financial market declines driven by COVID-19 have impacted us as follows:
The publicly traded price for our common stock (NYSE: WMB) declined 40 percent during the first quarter of 2020, including a 26 percent decline in the month of March. As a result, our board of directors approved a limited duration shareholder rights agreement. (See Note 10 – Stockholders’ Equity of Notes to the Consolidated Financial Statements.)
Driven by the decline in our market capitalization and the underlying decrease in fair value of our Northeast G&P reporting unit, we recognized a $187 million impairment of goodwill during the first quarter of 2020. (See Note 11 – Fair Value Measurements and Guarantees of Notes to the Consolidated Financial Statements.)
The same economic conditions impacted the fair value of certain of our equity-method investments, resulting in $938 million of other-than-temporary impairments of these investments in the first quarter of 2020. (See Note 11 – Fair Value Measurements and Guarantees of Notes to the Consolidated Financial Statements.)
Considering the decline in crude oil prices, we note the following about our businesses:
Our interstate natural gas transmission businesses are fully contracted under long-term firm reservation contracts with high credit quality customers and are not exposed to crude oil prices.
We believe counterparty credit concerns in our gathering and processing business are significantly mitigated by the physical nature of our services, where we gather at the wellhead and are therefore critical to a producer’s ability to move product to market.
Our on-shore natural gas gathering and processing businesses are substantially focused on gas-directed drilling basins rather than oil, with a broad diversity of basins and customers served. Further, a decline in oil drilling would be expected to result in less associated natural gas production, which could drive more demand for natural gas produced from gas-directed basins we serve.
Our deepwater transportation business is supported mostly by major oil producers with a long-cycle perspective.
NGL Margins
Per-unit non-ethane margins were approximately 24 percent lower in the first three months of 2020 compared to the same period in 2019 primarily due to a 35 percent decrease in per-unit non-ethane sales prices, partially offset by 42 percent lower per-unit natural gas feedstock prices.
NGL margins are defined as NGL revenues less any applicable Btu replacement cost, plant fuel, and third-party transportation and fractionation. Per-unit NGL margins are calculated based on sales of our own equity volumes at the processing plants. Our equity volumes include NGLs where we own the rights to the value from NGLs recovered at our plants under both “keep-whole” processing agreements, where we have the obligation to replace the lost heating value with natural gas, and “percent-of-liquids” agreements whereby we receive a portion of the extracted liquids with no obligation to replace the lost heating value.
The potential impact of commodity prices on our business for the remainder of 2020 is further discussed in the following Company Outlook.
Management’s Discussion and Analysis (Continued)
Filing of Rate Case
On August 31, 2018, Transco filed a general rate case with the FERC for an overall increase in rates. In September 2018, with the exception of certain rates that reflected a rate decrease, the FERC accepted and suspended our general rate filing to be effective March 1, 2019, subject to refund and the outcome of a hearing. The specific rates that reflected a rate decrease were accepted, without suspension, to be effective October 1, 2018, as requested by Transco, and were not subject to refund. In March 2019, the FERC accepted our motion to place the rates that were suspended by the September 2018 order into effect on March 1, 2019, subject to refund. In October 2019, we reached an agreement on the terms of a settlement with the participants that would resolve all issues in the rate case without the need for a hearing, and on December 31, 2019, we filed a formal stipulation and agreement with the FERC setting forth such terms of settlement. On March 24, 2020, the FERC issued an order approving the uncontested rate case settlement, which will become effective on June 1, 2020. As of March 31, 2020, we have provided a $248 million reserve for rate refunds related to increased rates collected since March 2019, which we believe is adequate for any refunds that may be required.
Company Outlook
Our strategy is to provide large-scale energy infrastructure designed to maximize the opportunities created by the vast supply of natural gas and natural gas products that exists in the United States. We accomplish this by connecting the growing demand for cleaner fuels and feedstocks with our major positions in the premier natural gas and natural gas products supply basins. We continue to maintain a strong commitment to safety, environmental stewardship, operational excellence, and customer satisfaction. We believe that accomplishing these goals will position us to deliver safe and reliable service to our customers and an attractive return to our shareholders.
Our business plan for 2020 includes a continued focus on earnings and cash flow growth, while continuing to improve leverage metrics and control operating costs. Many of our producer customers are impacted by extremely low energy commodity prices, which may result in a decrease in drilling activity and the temporary shut-in of existing production in certain oil-directed and liquids-rich areas. We are responding by reducing the pace of our capital growth spending in our gathering and processing business and remaining committed to operating cost discipline.
In the current environment, the credit profiles of certain of our producer customers are increasingly challenged. But as previously discussed, the physical nature of services we provide supports the success of these customers. In many cases, we have long-term acreage dedications with strong historical contractual conveyances that create real estate interest in unproduced gas. In exchange for such dedication of production, we invest capital to build gathering lines uniquely to serve a producer’s wells. Therefore, our gathering lines are physically connected to the customer’s wellheads and pads, conditioning and connecting the production to available markets. There may not be other gathering lines nearby. The construction of gathering systems is capital intensive and it would be very costly for others to replicate, especially considering the depletion to date of the associated reserves. As a result, we play a critical role in getting a customer’s production from the wellhead to a marketable condition and location. This tends to reduce collectability risk as our services enable producers to generate operating cash flows.
In 2020, our operating results are expected to include lower deferred revenue amortization related to the West’s Barnett Shale region and Gulfstar in the Eastern Gulf region. We also expect lower NGL margins overall and lower fee revenues in the West and Eastern Gulf region primarily from a decrease in drilling activity associated with a significant reduction in crude oil prices. Northeast results are expected to increase from higher gathering and processing volumes. If current market conditions persist, the temporary shut-in of existing onshore and offshore production in certain oil-directed and liquids-rich areas will decrease our results. We expect increases from Transco’s and Northwest Pipeline’s recent expansion projects placed in-service and Transco’s rate settlement as well as a full year contribution from the Norphlet project in the Eastern Gulf region. Additionally, we expect operating results will benefit from lower expenses associated with our recently implemented organizational realignment.
Our growth capital and investment expenditures in 2020 are expected to be in a range from $1.1 billion to $1.3 billion. Growth capital spending in 2020 primarily includes Transco expansions, all of which are fully contracted with firm transportation agreements, and our Bluestem NGL pipeline project in the Mid-Continent region. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments.
Management’s Discussion and Analysis (Continued)
Potential risks and obstacles that could impact the execution of our plan include:
Continued negative impacts of COVID-19 driving a global recession, which could result in further downturns in financial markets and commodity prices, as well as impact demand for natural gas and related products;
Opposition to, and legal regulations affecting, our infrastructure projects, including the risk of delay or denial in permits and approvals needed for our projects;
Counterparty credit and performance risk;
Unexpected significant increases in capital expenditures or delays in capital project execution;
Unexpected changes in customer drilling and production activities, which could negatively impact gathering and processing volumes;
Lower than anticipated demand for natural gas and natural gas products which could result in lower than expected volumes, energy commodity prices, and margins;
General economic, financial markets, or further industry downturn, including increased interest rates;
Physical damages to facilities, including damage to offshore facilities by named windstorms;
Other risks set forth under Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2019, as filed with the SEC on February 24, 2020, as supplemented by the disclosure in Part II, Item 1A. Risk Factors in this Quarterly Report on Form 10-Q.
We seek to maintain a strong financial position and liquidity, as well as manage a diversified portfolio of energy infrastructure assets which continue to serve key growth markets and supply basins in the United States.
Expansion Projects
Our ongoing major expansion projects include the following:
Transmission & Gulf of Mexico
Hillabee
In February 2016, the FERC issued a certificate order for the initial phases of Transco’s Hillabee Expansion Project. The project involves an expansion of Transco’s existing natural gas transmission system from Station 85 in west central Alabama to an interconnection with the Sabal Trail pipeline in Alabama. The project is being constructed in phases, and all of the project expansion capacity is dedicated to Sabal Trail pursuant to a capacity lease agreement. Phase I was completed in 2017 and it increased capacity by 818 Mdth/d. We placed Phase II into service on May 1, 2020. Together, the first two phases of the project increased capacity by 1,025 Mdth/d.
Northeast Supply Enhancement
In May 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from Station 195 in Pennsylvania to the Rockaway Delivery Lateral transfer point in New York. Approvals required for the project from the New York State Department of Environmental Conservation and the New Jersey Department of Environmental Protection remain pending, with each such agency having denied, without prejudice, Transco’s applications for such approvals. We have refiled our applications for those approvals and have addressed the technical issues identified by the agencies. We plan to place the project into service in the fall of 2021, assuming timely receipt of these remaining approvals. The project is expected to increase capacity by 400 Mdth/d.
Management’s Discussion and Analysis (Continued)
Southeastern Trail
In October 2019, we received approval from the FERC to expand Transco’s existing natural gas transmission system to provide incremental firm transportation capacity from the Pleasant Valley interconnect with Dominion’s Cove Point Pipeline in Virginia to the Station 65 pooling point in Louisiana. We plan to place the project into service in late 2020. The project is expected to increase capacity by 296 Mdth/d.
Leidy South
In July 2019, we filed an application with the FERC for approval of the project to expand Transco’s existing natural gas transmission system and also extend its system through a capacity lease with National Fuel Gas Supply Corporation that will enable us to provide incremental firm transportation from Clermont, Pennsylvania and from the Zick interconnection on Transco’s Leidy Line to the River Road regulating station in Lancaster County, Pennsylvania. We plan to place the project into service as early as the fourth quarter of 2021, assuming timely receipt of all necessary regulatory approvals. The project is expected to increase capacity by 582 Mdth/d.
West
Project Bluestem
We are expanding our presence in the Mid-Continent region through building a 188-mile NGL pipeline from our fractionator near Conway, Kansas to an interconnect with a third-party NGL pipeline system in Oklahoma, providing us with firm access to Mt. Belvieu pricing. As part of the project, the third-party intends to construct a 110-mile pipeline extension of their existing NGL pipeline system that will have an initial capacity of 120 Mbbls/d. Further, during the first quarter of 2019, we exercised an option to purchase a 20 percent equity interest in a Mt. Belvieu fractionation train developed by the third party. The pipeline and extension projects are expected to be placed into service during the first quarter of 2021.
Critical Accounting Estimates
Equity-Method Investments
We monitor our equity-method investments for any indications that the carrying value may have experienced an other-than-temporary decline in value.
In the first quarter of 2020, we observed a significant decline in the publicly traded price of our common stock (NYSE: WMB) as well as other industry peers and increases in equity yields within the midstream and overall energy industry, which served to increase our estimates of discount rates and weighted-average cost of capital. These changes were attributed to the swift, world-wide economic declines associated with actions to address the spread of COVID-19, coupled with the energy industry impact of significantly reduced energy commodity prices, which were further impacted by crude oil price declines associated with geopolitical actions during the quarter. These significant macroeconomic changes served as indications that the carrying amount of certain of our equity-method investments may have experienced an other-than temporary decline in fair value, determined in accordance with Accounting Standards Codification (ASC) Topic 323, “Investments - Equity Method and Joint Ventures.”
As a result, we estimated the fair value of these equity-method investments in accordance with ASC Topic 820, “Fair Value Measurement,” as of the March 31, 2020, measurement date. In assessing the fair value, we were required to consider recent publicly available indications of value, which included lower observed publicly traded EBITDA (earnings before interest, taxes, depreciation, and amortization) market multiples as compared with recent history, and significantly higher industry weighted-average discount rates. Although there have been recent improvements subsequent to March 31, 2020, it is difficult to predict the timing and degree of any sustained recovery. As a result, we have determined that there are other-than-temporary declines in the fair value of certain of our equity-method investments, resulting in recognized impairments totaling $938 million. (See Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements.) This included impairments of certain of our equity-method investments in our Northeast G&P segment totaling $405 million, primarily associated with operations in wet-gas areas where producer drilling activities are influenced by NGL prices, which historically trend with crude oil prices. This
Management’s Discussion and Analysis (Continued)
total was primarily comprised of impairments of our investment in Caiman II and predominantly wet gas gathering systems that are part of the Appalachia Midstream Investments. We also recognized an impairment of $97 million related to Discovery within the Transmission & Gulf of Mexico segment. We estimated the fair value of these investments as of the March 31, 2020, measurement date utilizing income and market approaches, which were impacted by assumptions reflecting the significant recent market declines previously discussed, such as higher discount rates, ranging from 9.7 percent to 13.5 percent, and lower EBITDA multiples ranging from 5.0x to 6.2x. We also considered any debt held at the investee level, and its impact to fair value. We estimate that a one percentage point increase or decrease in the discount rates used would increase these recognized impairments by approximately $197 million or decrease the level of these recognized impairments by approximately $121 million and a 0.5x increase or decrease in the EBITDA multiples assumed would decrease or increase the level of impairments recognized by approximately $48 million.
We also recognized $436 million of impairments within our West segment related to our investments in RMM and Brazos Permian II, measured using an income approach. Both investees operate in primarily crude oil-driven basins where our gathering volumes are driven by crude oil drilling. Our expectation of continued lower crude oil prices and related expectation of significant reductions in current and future producer activities in these areas led to reduced estimates of expected future cash flows. Our fair value estimates also reflected increases in the discount rates to approximately 17 percent for these investments. We also considered any debt held at the investee level, and its impact to fair value. We estimate that a one percentage point increase in the discount rate would increase these recognized impairments by approximately $32 million, while a one percentage point decrease would decrease these impairments by approximately $43 million.
Judgments and assumptions are inherent in our estimates of future cash flows, discount rates, and market measures utilized and, as previously discussed, were significantly impacted by the recent unfavorable macroeconomic changes. The use of alternate judgments and assumptions could result in a different calculation of fair value, which could ultimately result in the recognition of a different impairment charge in the consolidated financial statements, potentially including impairments for investments which were evaluated but for which no impairments were recognized.
Property, Plant, and Equipment and Other Identifiable Intangible Assets
As a result of the previously described significant macroeconomic changes during the first quarter of 2020, we also evaluated certain of our property, plant, and equipment and other identifiable intangible assets for indicators of impairment. In our assessments, we considered the impact of the current market conditions on certain of our assets and did not identify any indicators that the carrying amounts of those assets may not be recoverable. The use of alternate judgments or changes in future conditions could result in a different conclusion regarding the occurrence and measurement of impairments affecting the consolidated financial statements.
Management’s Discussion and Analysis (Continued)
Results of Operations
Consolidated Overview
The following table and discussion is a summary of our consolidated results of operations for the three months ended March 31, 2020, compared to the three months ended March 31, 2019. The results of operations by segment are discussed in further detail following this consolidated overview discussion.
|
| | | | | | | | | | | | | |
| Three Months Ended March 31, | | | | |
| 2020 | | 2019 | | $ Change* | | % Change* |
| (Millions) | | | | |
Revenues: | | | | | | | |
Service revenues | $ | 1,474 |
| | $ | 1,440 |
| | +34 |
| | +2 | % |
Service revenues – commodity consideration | 28 |
| | 64 |
| | -36 |
| | -56 | % |
Product sales | 411 |
| | 550 |
| | -139 |
| | -25 | % |
Total revenues | 1,913 |
| | 2,054 |
| | | | |
Costs and expenses: | | | | | | | |
Product costs | 396 |
| | 525 |
| | +129 |
| | +25 | % |
Processing commodity expenses | 13 |
| | 40 |
| | +27 |
| | +68 | % |
Operating and maintenance expenses | 337 |
| | 340 |
| | +3 |
| | +1 | % |
Depreciation and amortization expenses | 429 |
| | 416 |
| | -13 |
| | -3 | % |
Selling, general, and administrative expenses | 113 |
| | 128 |
| | +15 |
| | +12 | % |
Impairment of goodwill | 187 |
| | — |
| | -187 |
| | NM |
|
Other (income) expense – net | 7 |
| | 44 |
| | +37 |
| | +84 | % |
Total costs and expenses | 1,482 |
| | 1,493 |
| | | | |
Operating income (loss) | 431 |
| | 561 |
| | | | |
Equity earnings (losses) | 22 |
| | 80 |
| | -58 |
| | -73 | % |
Impairment of equity-method investments | (938 | ) | | (74 | ) | | -864 |
| | NM |
|
Other investing income (loss) – net | 3 |
| | 1 |
| | +2 |
| | +200 | % |
Interest expense | (296 | ) | | (296 | ) | | — |
| | — | % |
Other income (expense) – net | 4 |
| | 11 |
| | -7 |
| | -64 | % |
Income (loss) before income taxes | (774 | ) | | 283 |
| | | | |
Provision (benefit) for income taxes | (204 | ) | | 69 |
| | +273 |
| | NM |
|
Net income (loss) | (570 | ) | | 214 |
| | | | |
Less: Net income (loss) attributable to noncontrolling interests | (53 | ) | | 19 |
| | +72 |
| | NM |
|
Net income (loss) attributable to The Williams Companies, Inc. | $ | (517 | ) | | $ | 195 |
| | | | |
| |
* | + = Favorable change; - = Unfavorable change; NM = A percentage calculation is not meaningful due to a change in signs, a zero-value denominator, or a percentage change greater than 200. |
Three months ended March 31, 2020 vs. three months ended March 31, 2019
Service revenuesincreased primarily due to higher Northeast revenues driven by higher volumes and the March 2019 consolidation of UEOM, as well as higher transportation fee revenues at Transco primarily associated with its rate case settlement and expansion projects placed in service in 2019. This increase was partially offset by the expiration of an MVC agreement in the Barnett Shale region and lower deferred revenue amortization at Gulfstar.
Service revenues – commodity consideration decreased primarily due to lower equity NGL processing volumes due to higher ethane rejection and less producer drilling activity in addition to lower commodity prices. These revenues represent consideration we receive in the form of commodities as full or partial payment for processing services provided. Most of these NGL volumes are sold within the month processed and therefore are offset in Product costs below.
Management’s Discussion and Analysis (Continued)
Product salesdecreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL sales activities, as well as lower volumes associated with our equity NGL sales activities, partially offset by higher marketing volumes. This decrease also includes lower system management gas sales. Marketing revenues and system management gas sales are substantially offset in Product costs.
Product costs decreased primarily due to lower NGL and natural gas prices associated with our marketing and equity NGL production activities. This decrease also includes lower volumes acquired as commodity consideration for NGL processing services and lower system management gas costs, partially offset by higher volumes for marketing activities.
Processing commodity expenses decreased primarily due to lower natural gas purchases associated with equity NGL production primarily due to lower volumes and lower natural gas prices.
Operating and maintenance expenses decreased due to lower maintenance and employee-related expenses, substantially offset by higher expenses related to the consolidation of UEOM in March 2019.
Depreciation and amortization expenses increased primarily due to the March 2019 consolidation of UEOM and new assets placed in service, partially offset by lower expense related to assets that became fully depreciated in the fourth quarter of 2019.
Selling, general, and administrative expenses decreased primarily due to lower employee-related expenses.
Impairment of goodwill reflects the goodwill impairment charge at Northeast G&P in 2020 (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The favorable change in Other (income) expense – net within Operating income (loss) includes net favorable changes to regulatory assets and liabilities primarily associated with Transco’s rate case settlement, as well as the absence of both a 2019 impairment of a certain asset at West and a 2019 unfavorable regulatory asset adjustment at Other.
The unfavorable change in Operating income (loss) includes the 2020 impairment of goodwill at Northeast G&P, lower deferred revenue amortization in the West and at Gulfstar, and unfavorable commodity margins primarily reflecting lower NGL sales prices. The unfavorable change was partially offset by higher volumes in the Northeast, the favorable impacts of the consolidation of UEOM, and Transco's rate case settlement.
Equity earnings (losses) decreased primarily due to our share of the 2020 impairment of goodwill at RMM (see Note 5 – Investing Activities of Notes to Consolidated Financial Statements). This decrease was partially offset by an increase at Appalachia Midstream Investments.
Impairment of equity-method investments includes impairments of various equity-method investments in 2020, partially offset by the absence of a 2019 impairment of UEOM (see Note 11 – Fair Value Measurements and Guarantees of Notes to Consolidated Financial Statements).
The unfavorable change in Other income (expense) – net below Operating income (loss) is primarily due to a 2020 pension plan settlement charge.
Provision (benefit) for income taxes changed favorably primarily due to lower pre-tax income. See Note 6 – Provision (Benefit) for Income Taxes of Notes to Consolidated Financial Statements for a discussion of the effective tax rate compared to the federal statutory rate for both periods.
The favorable change in Net income (loss) attributable to noncontrolling interests is primarily due to the goodwill impairment and lower Gulfstar results, partially offset by increased results related to the formation of the Northeast JV in June 2019.
Management’s Discussion and Analysis (Continued)
Period-Over-Period Operating Results - Segments
We evaluate segment operating performance based upon Modified EBITDA. Note 13 – Segment Disclosures of Notes to Consolidated Financial Statements includes a reconciliation of this non-GAAP measure to Net income (loss). Management uses Modified EBITDA because it is an accepted financial indicator used by investors to compare company performance. In addition, management believes that this measure provides investors an enhanced perspective of the operating performance of our assets. Modified EBITDA should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP.
Transmission & Gulf of Mexico
|
| | | | | | | |
| Three Months Ended March 31, |
| 2020 | | 2019 |
| (Millions) |
Service revenues | $ | 829 |
| | $ | 823 |
|
Service revenues – commodity consideration | 5 |
| | 13 |
|
Product sales | 52 |
| | 82 |
|
Segment revenues | 886 |
| | 918 |
|
| | | |
Product costs | (52 | ) | | (82 | ) |
Processing commodity expenses | (2 | ) | | (5 | ) |
Other segment costs and expenses | (214 | ) | | (237 | ) |
Proportional Modified EBITDA of equity-method investments | 44 |
| | 42 |
|
Transmission & Gulf of Mexico Modified EBITDA | $ | 662 |
| | $ | 636 |
|
| | | |
Commodity margins | $ | 3 |
| | $ | 8 |
|
Three months ended March 31, 2020 vs. three months ended March 31, 2019
Transmission & Gulf of Mexico Modified EBITDA increased primarily due to favorable changes to Other segment costs and expenses and increased Service revenues.
Service revenues increased primarily due to a $32 million increase in Transco’s natural gas transportation revenues primarily driven by higher revenues from Transco’s rate case settlement and expansion projects placed in service in 2019. This increase was partially offset by $29 million lower gathering, processing, and other transportation fees primarily due to lower deferred revenue amortization at Gulfstar.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins. Our commodity margins associated with our equity NGLs decreased $4 million primarily driven by unfavorable NGL sales prices. Additionally, the decrease in Product sales includes a $16 million decrease in commodity marketing sales and $6 million lower system management gas sales primarily due to lower NGL prices. Marketing revenues and system management gas sales are substantially offset in Product costs and therefore have little impact to Modified EBITDA.
Other segment costs and expenses decreased primarily due to net favorable changes associated with regulatory assets and liabilities primarily driven by the terms of settlement in Transco’s general rate case, as well as decreased maintenance costs and lower employee-related costs.
Management’s Discussion and Analysis (Continued)
Northeast G&P
|
| | | | | | | |
| Three Months Ended March 31, |
| 2020 | | 2019 |
| (Millions) |
Service revenues | $ | 358 |
| | $ | 276 |
|
Service revenues – commodity consideration | 2 |
| | 5 |
|
Product sales | 29 |
| | 47 |
|
Segment revenues | 389 |
| | 328 |
|
| | | |
Product costs | (29 | ) | | (47 | ) |
Processing commodity expenses | (1 | ) | | (3 | ) |
Other segment costs and expenses | (110 | ) | | (101 | ) |
Proportional Modified EBITDA of equity-method investments | 120 |
| | 122 |
|
Northeast G&P Modified EBITDA | $ | 369 |
| | $ | 299 |
|
| | | |
Commodity margins | $ | 1 |
| | $ | 2 |
|
Three months ended March 31, 2020 vs. three months ended March 31, 2019
Northeast G&P Modified EBITDA increased primarily due to higher Service revenues and the favorable impact of acquiring the additional interest of UEOM, which is a consolidated entity after the remaining ownership interest was purchased in March 2019, in addition to increased Proportional Modified EBITDA of equity-method investments from higher volumes at Appalachia Midstream Investments and Caiman II.
Service revenues increased primarily due to:
| |
• | A $68 million increase at the Northeast JV, including a $32 million increase associated with the consolidation of UEOM, as previously discussed, $8 million associated with higher UEOM volumes, and $20 million higher gathering, processing, fractionation, and transportation revenues from our Ohio Valley Midstream business due to higher volumes. Additionally, revenues increased related to $8 million of higher amounts for reimbursable electricity expenses, which are offset by similar changes in electricity charges, reflected above in Other segment costs and expenses;
|
An $8 million increase in gathering revenues at Cardinal primarily due to higher rates;
A $6 million increase in gathering revenues at Susquehanna Supply Hub.
Product sales decreased primarily due to lower non-ethane volumes within our marketing activities. The changes in marketing revenues are offset by similar changes in marketing purchases, reflected above as Product costs.
Other segment costs and expenses increased primarily due to the consolidation of UEOM in addition to higher reimbursable electricity expenses. These increases are partially offset by lower costs related to various maintenance and repairs and employee expenses.
Proportional Modified EBITDA of equity-method investments decreased $16 million as a result of the consolidation of UEOM, as previously discussed. This decrease was substantially offset by increases at Appalachia Midstream Investments and Caiman II driven by higher volumes.
Management’s Discussion and Analysis (Continued)
West
|
| | | | | | | |
| Three Months Ended March 31, |
| 2020 | | 2019 |
| (Millions) |
Service revenues | $ | 311 |
| | $ | 359 |
|
Service revenues – commodity consideration | 21 |
| | 46 |
|
Product sales | 359 |
| | 479 |
|
Segment revenues | 691 |
| | 884 |
|
| | | |
Product costs | (368 | ) | | (475 | ) |
Processing commodity expenses | (10 | ) | | (31 | ) |
Other segment costs and expenses | (126 | ) | | (148 | ) |
Proportional Modified EBITDA of equity-method investments | 28 |
| | 26 |
|
West Modified EBITDA | $ | 215 |
| | $ | 256 |
|
| | | |
Commodity margins | $ | 2 |
| | $ | 19 |
|
Three months ended March 31, 2020 vs. three months ended March 31, 2019
West Modified EBITDA decreased primarily due to lower Service revenues and lower Commodity margins due to unfavorable commodity prices, partially offset by lower Other segment costs and expenses.
Service revenues decreased primarily due to:
A $38 million decrease driven by lower deferred revenue amortization and MVC deficiency fee revenues associated with the expiration of the MVC agreement in the Barnett Shale region;
A $23 million decrease associated with lower rates driven by lower commodity pricing in the Barnett Shale region and the expiration of a cost-of-service period on a contract in the Mid-Continent region;
A $12 million decrease associated with lower volumes;
A $26 million increase in the Eagle Ford Shale region.
The net sum of Service revenues – commodity consideration, Product sales, Product costs, and Processing commodity expenses comprise our commodity margins, which we further segregate into product margins associated with our equity NGLs and marketing margins. Product margins from our equity NGLs decreased $4 million primarily due to:
A $16 million decrease associated with lower sales volumes primarily due to 87 percent lower ethane sales volumes primarily due to higher ethane rejection as well as 18 percent lower non-ethane sales volumes primarily due to less producer drilling activity;
A $10 million decrease associated with lower sales prices primarily due to 32 percent lower average net realized per-unit non-ethane sales prices;
A $22 million increase related to a decrease in natural gas purchases associated with lower equity NGL production volumes and lower natural gas prices.
Additionally, marketing margins decreased by $13 million primarily due to unfavorable changes in prices. The decrease in Product sales includes an $88 million decrease in marketing sales, which is due to lower sales prices, partially offset by higher marketing sales volumes. These decreases are substantially offset in Product costs.
Management’s Discussion and Analysis (Continued)
Other segment costs and expenses decreased primarily due the absence of a $12 million 2019 impairment of assets and lower operating and maintenance and general and administrative costs due primarily to lower employee-related costs and maintenance expenses.
Proportional Modified EBITDA of equity-method investments increased primarily due to increased activity at the RMM equity-method investment, partially offset by the absence of the Jackalope equity-method investment sold in April 2019.
Other
|
| | | | | | | |
| Three Months Ended March 31, |
| 2020 | | 2019 |
| (Millions) |
Other Modified EBITDA | $ | 7 |
| | $ | (4 | ) |
Three months ended March 31, 2020 vs. three months ended March 31, 2019
Other Modified EBITDA increased primarily due to the absence of a first-quarter 2019 $12 million unfavorable adjustment to a regulatory asset associated with an increase in Transco’s estimated deferred state income tax rate following the merger transaction wherein we acquired all of the outstanding common units held by others of our former publicly traded master limited partnership.
Management’s Discussion and Analysis (Continued)
Management’s Discussion and Analysis of Financial Condition and Liquidity
Outlook
As previously discussed in Company Outlook, our growth capital and investment expenditures in 2020 are currently expected to be in a range from $1.1 billion to $1.3 billion. Growth capital spending in 2020 includes Transco expansions, all of which are fully contracted with firm transportation agreements, and our Bluestem NGL pipeline project in the Mid-Continent region. In addition to growth capital and investment expenditures, we also remain committed to projects that maintain our assets for safe and reliable operations, as well as projects that meet legal, regulatory, and/or contractual commitments. We intend to fund substantially all of our planned 2020 capital spending with cash available after paying dividends. We retain the flexibility to adjust planned levels of growth capital and investment expenditures in response to changes in economic conditions or business opportunities.
During the first quarter of 2020, we retired $1.514 billion of long-term debt utilizing proceeds borrowed under our credit facility. We have an additional $607 million of long-term debt maturing in 2020. Potential sources of liquidity available to address our debt maturities include proceeds from the issuance of new debt, available capacity under our credit facility, and proceeds from any asset monetizations.
Liquidity
Based on our forecasted levels of cash flow from operations and other sources of liquidity, we expect to have sufficient liquidity to manage our businesses in 2020. Our potential material internal and external sources and uses of liquidity are as follows:
|
| |
Sources: | |
| Cash and cash equivalents on hand |
| Cash generated from operations |
| Distributions from our equity-method investees |
| Utilization of our credit facility and/or commercial paper program |
| Cash proceeds from issuance of debt and/or equity securities |
| Proceeds from asset monetizations |
| Contributions from noncontrolling interests |
| |
Uses: | |
| Working capital requirements |
| Capital and investment expenditures |
| Quarterly dividends to our shareholders |
| Debt service payments, including payments of long-term debt |
| Distributions to noncontrolling interests |
Potential risks associated with our planned levels of liquidity discussed above include those previously discussed in Company Outlook.
Management’s Discussion and Analysis (Continued)
As of March 31, 2020, we had a working capital deficit of $551 million, including cash and cash equivalents and long-term debt due within one year. Our available liquidity is as follows:
|
| | | |
Available Liquidity | March 31, 2020 |
| (Millions) |
Cash and cash equivalents | $ | 400 |
|
Capacity available under our $4.5 billion credit facility, less amounts outstanding under our $4 billion commercial paper program (1) | 2,800 |
|
| $ | 3,200 |
|
| |
(1) | In managing our available liquidity, we do not expect a maximum outstanding amount in excess of the capacity of our credit facility inclusive of any outstanding amounts under our commercial paper program. We had no commercial paper outstanding as of March 31, 2020. Through March 31, 2020, the highest amount outstanding under our commercial paper program and credit facility during 2020 was $1.7 billion. At March 31, 2020, we were in compliance with the financial covenants associated with our credit facility. Borrowing capacity available under our credit facility as of May 1, 2020, was $2.8 billion. |
Dividends
We increased our regular quarterly cash dividend to common stockholders by approximately 5 percent from the previous quarterly cash dividends of $0.38 per share paid in each quarter of 2019, to $0.40 per share for the quarterly cash dividends paid in March 2020.
Registrations
In February 2018, we filed a shelf registration statement as a well-known seasoned issuer. In August 2018, we filed a prospectus supplement for the offer and sale from time to time of shares of our common stock having an aggregate offering price of up to $1 billion. These sales are to be made over a period of time and from time to time in transactions at then-current prices. Such sales are to be made pursuant to an equity distribution agreement between us and certain entities who may act as sales agents or purchase for their own accounts as principals at a price agreed upon at the time of the sale.
Distributions from Equity-Method Investees
The organizational documents of entities in which we have an equity-method investment generally require distribution of their available cash to their members on a quarterly basis. In each case, available cash is reduced, in part, by reserves appropriate for operating their respective businesses.
Credit Ratings
The interest rates at which we are able to borrow money are impacted by our credit ratings. The current ratings are as follows:
|
| | | | |
Rating Agency | | Outlook | | Senior Unsecured
Debt Rating
|
S&P Global Ratings | | Stable | | BBB |
Moody’s Investors Service | | Stable | | Baa3 |
Fitch Ratings | | Stable | | BBB- |
These credit ratings are included for informational purposes and are not recommendations to buy, sell, or hold our securities, and each rating should be evaluated independently of any other rating. No assurance can be given that the credit rating agencies will continue to assign us investment-grade ratings even if we meet or exceed their current criteria for investment-grade ratios. A downgrade of our credit ratings might increase our future cost of borrowing and would require us to provide additional collateral to third parties, negatively impacting our available liquidity.
Management’s Discussion and Analysis (Continued)
Sources (Uses) of Cash
The following table summarizes the sources (uses) of cash and cash equivalents for each of the periods presented (see Notes to Consolidated Financial Statements for the Notes referenced in the table):
|
| | | | | | | | | |
| Cash Flow | | Three Months Ended March 31, |
| Category | | 2020 | | 2019 |
| | | (Millions) |
Sources of cash and cash equivalents: | | | | | |
Operating activities – net | Operating | | $ | 787 |
| | $ | 775 |
|
Proceeds from credit-facility borrowings | Financing | | 1,700 |
| | 700 |
|
Proceeds from commercial paper – net | Financing | | — |
| | 1,014 |
|
| | | | | |
Uses of cash and cash equivalents: | | | | | |
Payments of long-term debt | Financing | | (1,518 | ) | | (4 | ) |
Common dividends paid | Financing | | (485 | ) | | (460 | ) |
Capital expenditures | Investing | | (306 | ) | | (422 | ) |
Dividends and distributions paid to noncontrolling interests | Financing | | (44 | ) | | (41 | ) |
Purchases of and contributions to equity-method investments | Investing | | (30 | ) | | (99 | ) |
Payments on credit-facility borrowings | Financing | | — |
| | (860 | ) |
Purchases of businesses, net of cash acquired (see Note 2) | Investing | | — |
| | (727 | ) |
| | | | | |
Other sources / (uses) – net | Financing and Investing | | 7 |
| | (1 | ) |
Increase (decrease) in cash and cash equivalents | | | $ | 111 |
| | $ | (125 | ) |
Operating activities
The factors that determine operating activities are largely the same as those that affect Net income (loss), with the exception of noncash items such as Depreciation and amortization, Provision (benefit) for deferred income taxes, Equity (earnings) losses, Impairment of goodwill, and Impairment of equity-method investments. Our Net cash provided (used) by operating activities for the three months ended March 31, 2020, increased from the same period in 2019 primarily due to higher operating income (excluding noncash items as previously discussed) in 2020.
Off-Balance Sheet Arrangements and Guarantees of Debt or Other Commitments
We have various other guarantees and commitments which are disclosed in Note 4 – Variable Interest Entities, Note 11 – Fair Value Measurements and Guarantees, and Note 12 – Contingent Liabilities of Notes to Consolidated Financial Statements. We do not believe these guarantees and commitments or the possible fulfillment of them will prevent us from meeting our liquidity needs.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
Our current interest rate risk exposure is related primarily to our debt portfolio and has not materially changed during the first three months of 2020.2021.
Item 4. Controls and Procedures
Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures (as defined in Rules 13a - 15(e) and 15d - 15(e) of the Securities Exchange Act of 1934, as amended) (Disclosure Controls) or our internal control over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and Internal Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the end of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these Disclosure Controls are effective at a reasonable assurance level.
Changes in Internal Control Over Financial Reporting
There have been no changes during the first quarter of 20202021 that have materially affected, or are reasonably likely to materially affect, our Internal Control over Financial Reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Environmental
Certain reportable legal proceedings involving governmental authorities under federal, state, and local laws regulating the discharge of materials into the environment are described below. While it is not possible for us to predict the final outcome of the proceedings whichthat are still pending, we do not anticipate a material effect on our consolidated financial position if we receive an unfavorable outcome in any one or more of such proceedings.
On June 13, 2013, an explosion and fire occurred at our formerly owned Geismar olefins plant and rendered the facility temporarily inoperable (Geismar Incident). On October 21, 2013, the EPA, Region 6, issued an Inspection Report pursuant to the Clean Air Act’s Risk Management Program following its inspection of the facility on June 24 through June 28, 2013. The report notes the EPA’s preliminary determinations about the facility’s documentation regarding process safety, process hazard analysis, as well as operating procedures, employee training, and other matters.
On June 16, 2014, we received Our threshold for disclosing material environmental legal proceedings involving a request for information related to the Geismar Incident from the EPA under Section 114 of the Clean Air Act to which we responded on August 13, 2014. We have worked with the agency to resolve these matters and in the second half of 2019, entered into a Stipulation of Settlement, which includes a penalty of $750,000 that will be due within thirty days of the Court’s entry of the settlement. The Court set a fairness hearing on the settlement for December 11, 2019. Prior to the scheduled hearing, the Court continued the hearing without setting a new date.
On May 5, 2017, we entered into a Consent Order with the Georgia Department of Natural Resources, Environmental Protection Division (GADNR) pertaining to alleged violations of the Georgia Water Quality Control Act and associated rules arising from a permit issued by GADNR for construction of Transco’s Dalton expansion project. Pursuant to the Consent Order, we paid a fine of $168,750 and agreed to a Corrective Action Plan. On March 26, 2020, the GADNR issued a closure letter to Transco approving the final Corrective Action Plan implementation and acknowledging that all conditions of the Consent Order have been achieved.governmental authority where potential monetary sanctions are involved is $1 million.
On January 19, 2016, we received a Notice of Noncompliance with certain Leak Detection and Repair (LDAR) regulations under the Clean Air Act at our Moundsville Fractionator Facility from the EPA, Region 3. Subsequently,
the EPA alleged similar violations of certain LDAR regulations at our Oak Grove Gas Plant. On March 19, 2018, we received a Notice of Violation of certain LDAR regulations at our former Ignacio Gas Plant from the EPA, Region 8, following an on-site inspection of the facility. On March 20, 2018, we also received a Notice of Violation of certain LDAR regulations at our Parachute Creek Gas Plant from the EPA, Region 8. All Noticessuch notices were subsequently referred to a common attorney at the Department of Justice (DOJ). We are exploring global resolution of the claims at these facilities, as well as alleged violations at certain other facilities, with the DOJ. Global resolution would include both payment of a civil penalty and an injunctive relief component. We continue to work with the DOJ and the other agencies to resolve these claims, whether individually or globally, and negotiations are ongoing.
Other environmental matters called for by this Item are described under the caption “Environmental Matters” in Note 1211 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this Item.
Other litigation
The additional information called for by this Item is provided in Note 129 – Stockholders’ Equity and Note 11 – Contingent Liabilities of Notes to Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this Item.
Item 1A. Risk Factors
Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2019,2020, includes risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially changed, except that they are supplemented or modified bychanged.
Item 5. Other Information
On April 28, 2021, we and Williams Field Services Group, LLC, an indirect wholly owned subsidiary of ours (Williams FSG), entered into an Equity Purchase Agreement (the Purchase Agreement) with Southern Company Gas Investments, Inc. (SECC Seller), Sequent Holdings, LLC, (SEM LP Seller), Sequent, LLC (SEM GP Seller and, together with SECC Seller and SEM LP Seller, the following risk factors:
Prices forSellers) and Southern Company Gas (Seller Parent), pursuant to which the Sellers have agreed to sell, and Williams FSG has agreed to buy, (i) a ninety-nine percent limited partnership interest in Sequent Energy Management, L.P. (SEM), (ii) a one percent general partner interest in SEM, and (iii) all of the outstanding shares of common stock of Sequent Energy Canada Corp. (SECC and together with SEM, the Companies). The Companies provide natural gas NGLs, oil,marketing and logistics services. The purchase price is $50 million plus working capital acquired. The Base Purchase Price as defined in the Purchase Agreement, which includes a $60 million target for acquired working capital, is $110 million, subject to adjustment for actual working capital relative to the target as well as certain other commodities, are volatilecustomary adjustments.
The Purchase Agreement contains customary (i) representations and this volatility haswarranties, (ii) covenants, including with respect to actions taken prior to the closing, cooperation with respect to regulatory issues, and could continue to adversely affect our financial condition, results of operations, cash flows, access to capital,information, and ability(iii) indemnification provisions. Williams FSG will obtain a customary buyer’s representation and warranty insurance policy. The Purchase Agreement is subject to maintaincustomary closing conditions, including the expiration or grow our businesses.termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
Our revenues, operating results, future rate
We have agreed to guarantee the obligations of growth,Williams FSG under the Purchase Agreement. At closing, we will also issue a payment performance guarantee to Seller Parent equal to Seller Parent’s outstanding guarantee obligation with respect to the Companies’ payment performance from the period after the transaction closes until Seller Parent is released from those obligations. We anticipate issuing replacement guarantees directly to the Companies’ counterparties to obtain such release of Seller Parent. The total amount of such obligations varies based on changes in natural gas prices, market conditions, and the valuenumber of certain componentsactive contracts and transactions of the Companies with counterparties. We anticipate combined volumes from the Companies’ business and our businesses depend primarily upon the prices ofexisting natural gas NGLs, oil, or other commodities, andmarketing business will exceed 8 Bcf/d, which we believe would be in the differences between pricestop five of these commodities and could be materially adversely affected by an extended period of low commodity prices, or a decline in commodity prices. Price volatility has and could continue to impact both the amount we receive for our products and services and the volume of products and services we sell. Prices affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Price volatility has and could continue to have an adverse effect on our business, results of operations, financial condition, and cash flows.North American natural gas marketers.
The markets for natural gas, NGLs, oil, and other commodities are likely to continue to be volatile. As an example, the recent “oil price war” between Russia and Saudi Arabia combined with existing oil production,Purchase Agreement contains certain termination rights, including by domestic producers, and the rapid drop in demand for oil due to the economic impactmutual written consent of the COVID-19 pandemic resulted in a
significant oversupply of oil and negatively impacted pricing. Wide fluctuations in prices might result from oneparties or more factors beyond our control, including:
Imbalances in supply and demand whether rising from worldwide or domestic supplies of and demand for natural gas, NGLs, oil, and related commodities;
Turmoil inif, subject to certain conditions, the Middle East and other producing regions;
The activities of the Organization of Petroleum Exporting Countries (OPEC) and other countries, whether acting independently of or informally aligned with OPEC, which have significant oil, natural gas or other commodity production capabilities including Russia;
The level of consumer demand;
The price and availability of other types of fuels or feedstocks;
The availability of pipeline capacity;
Supply disruptions, including plant outages and transportation disruptions;
The price and quantity of foreign imports and domestic exports of natural gas and oil;
Domestic and foreign governmental regulations and taxes;
The credit of participants in the markets where products are bought and sold.
We face risks related to the COVID-19 pandemic and other health epidemics.
The global outbreak of the novel coronavirus (COVID-19) is currently impacting countries, communities, supply chains, and markets. We provide a critical service to our customers, which means that it is paramount that we keep our employees safe. To date, COVID-19closing has not had a material impactoccurred on our business operations. However, we cannot predict whether, andor before August 26, 2021. We expect closing to occur during the extent to which, COVID-19 will have a material impact on our business, including our liquidity, financial condition, and resultsthird quarter of operations. COVID-19 could pose a risk to our employees, our customers, our suppliers, and the communities in which we operate, which could negatively impact our business. To the extent that our access to the capital markets is adversely affected by COVID-19, we may need to consider alternative sources of funding for our operations and for working capital, any of which could increase our cost of capital. Measures to try to contain the virus, such as travel bans and restrictions, quarantines, shelter in place orders, and shutdowns, may cause us to experience operational delays or to delay plans for growth. The extent to which COVID-19 may impact our business will depend on future developments, which are highly uncertain and cannot be predicted, including new information concerning the severity of COVID-19 and the actions taken to contain it or treat its impact, among others.2021.
To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other factors described in the Risk Factors disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2019.
Item 6. Exhibits
| | | | | | | | | | | | | | |
Exhibit No. | | | | Description |
| | | | |
Exhibit
No. 2.1 | | — | | Description |
| | | | |
2.1 | | — | | |
2.2 | | — | | Amendment No 1. to Agreement and Plan of Merger dated as of May 1, 2016, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC, and Energy Transfer Equity GP, LLC (filed on May 3, 2016 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
2.3 | | — | | Agreement and Plan of Merger dated as of September 28, 2015, by and among The Williams Companies, Inc., Energy Transfer Corp LP, Energy Transfer Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC, and Energy Transfer Equity GP, LLC (filed on October 1, 2015 as Exhibit 2.1 to The Williams Companies, Inc.’s current report on Form 8-K (File No. 001-04174) and incorporated herein by reference). |
3.1 | | — | | |
3.2 | | — | | —
| | |
3.3 | | — | | —
| | |
3.4 | | — | | |
3.5 | | — | | |
4.1 | | — | | Rights Agreement,Fourth Supplemental Indenture, dated as of March 20, 2020,2, 2021, between The Williams Companies, Inc. and ComputershareThe Bank of New York Mellon Trust Company, N.A., as Rights Agent, which includes for Form of Certificate of Designation of Series C Participating Cumulative Preferred Stock of The Williams Companies, Inc. as Exhibit A, the Summary of Terms of the Rights Agreement as Exhibit B and the Form of Rights Certificate as Exhibit Ctrustee (filed on March 20, 20202, 2021 as Exhibit 4.1 to The Williams Companies, Inc.’s current report on Form 8‑K (File No. 001-04174001-04174) and incorporated herein by references)reference). |
10.1§* | | — | | |
10.2§* | | — | | |
10.3§*31.1* | | — | | |
10.4§* | | — | | |
31.1* | | — | | |
|
31.2* | | — | | |
Exhibit
No.
| | | | Description |
| | | | |
31.2* | | — | | |
32** | | — | | |
101.INS* | | — | | XBRL Instance Document. The instance document does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document. |
101.SCH* | | — | | XBRL Taxonomy Extension Schema. |
101.CAL* | | — | | XBRL Taxonomy Extension Calculation Linkbase. |
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101.DEF*Exhibit No. | | — | | Description |
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101.DEF* | | — | | XBRL Taxonomy Extension Definition Linkbase. |
101.LAB* | | — | | XBRL Taxonomy Extension Label Linkbase. |
101.PRE* | | — | | XBRL Taxonomy Extension Presentation Linkbase. |
104* | | — | | Cover Page Interactive Data File. The cover page interactive data file does not appear in the interactive data file because its XBRL tags are embedded within the inline XBRL document (contained in Exhibit 101). |
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§ | Management contract or compensatory plan or arrangement. |
§ Management contract or compensatory plan or arrangement.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
| | | | |
| THE WILLIAMS COMPANIES, INC. |
| (Registrant) |
| |
| /s/ John D. Porter |
| John D. Porter |
| Vice President, Controller, and Chief Accounting Officer (Duly Authorized Officer and Principal Accounting Officer) |
May 4, 20203, 2021