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(Exact name of registrant as specified in its charter)
iDelaware
i73-0569878
(State
or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
iOne Williams Center
iTulsa
iOklahoma
i74172-0172
(Address
of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code: (i918) i573-2000
NO CHANGE
(Former
name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
iCommon Stock,
$1.00 par value
iWMB
iNew York Stock Exchange
Indicate by check mark whether the registrant (1) has filed all reports required to
be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. iYes☑No☐
Indicate by check mark whether the
registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). iYes☑ No ☐
Indicate by check mark whether the
registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer,”“smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
iLarge
accelerated filer
☑
Accelerated filer
☐
Non-accelerated filer
☐
Smaller reporting company
i☐
Emerging
growth company
i☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yesi☐No☑
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
The reports, filings, and other public announcements of The Williams Companies, Inc. (Williams) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcomes of regulatory proceedings, market conditions,
and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
All statements, other than statements of historical facts, included in this report that address activities, events, or developments that we expect, believe, or anticipate will exist or may occur in the future are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,”“believes,”“seeks,”“could,”“may,”“should,”“continues,”“estimates,”“expects,”“forecasts,”“intends,”“might,”“goals,”“objectives,”“targets,”“planned,”“potential,”“projects,”“scheduled,”“will,”“assumes,”“guidance,”“outlook,”“in-service date,” or
other similar expressions. These forward-looking statements are based on management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
•Levels of dividends to Williams stockholders;
•Future credit ratings of Williams and its affiliates;
•Amounts and nature of future capital expenditures;
•Expansion and growth of our business and operations;
•Expected in-service dates for capital projects;
1
•Financial
condition and liquidity;
•Business strategy;
•Cash flow from operations or results of operations;
•Seasonality of certain business components;
•Natural gas, natural gas liquids, and crude oil prices, supply, and demand;
•Demand for our services;
•The impact of the coronavirus (COVID-19) pandemic.
Forward-looking statements are based on numerous assumptions, uncertainties, and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will
determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
•Availability of supplies, market demand, and volatility of prices;
•Development and rate of adoption of alternative energy sources;
•The impact of existing and future laws and regulations, the regulatory environment, environmental matters, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes;
•Our exposure to the credit risk of our customers and counterparties;
•Our
ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities, and to consummate asset sales on acceptable terms;
•Whether we are able to successfully identify, evaluate, and timely execute our capital projects and investment opportunities;
•The strength and financial resources of our competitors and the effects of competition;
•The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate;
•Whether we will be able to effectively execute our financing plan;
•Increasing
scrutiny and changing expectations from stakeholders with respect to our environmental, social, and governance practices;
•The physical and financial risks associated with climate change;
•The impacts of operational and developmental hazards and unforeseen interruptions;
•The risks resulting from outbreaks or other public health crises, including COVID-19;
•Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities;
•Acts of terrorism, cybersecurity incidents, and related disruptions;
•Our costs and funding
obligations for defined benefit pension plans and other postretirement benefit plans;
2
•Changes in maintenance and construction costs, as well as our ability to obtain sufficient construction-related inputs, including skilled labor;
•Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers);
•Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally recognized credit rating agencies, and the
availability and cost of capital;
•The ability of the members of the Organization of Petroleum Exporting Countries (OPEC) and other oil exporting nations to agree to and maintain oil price and production controls and the impact on domestic production;
•Changes in the current geopolitical situation;
•Changes in U.S. governmental administration and policies;
•Whether we are able to pay current and expected levels of dividends;
•Additional risks described in our filings with the Securities and Exchange Commission (SEC).
Given the uncertainties and risk factors that could cause our actual results
to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise.
Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above,
that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020, as filed with the SEC on February 24, 2021.
3
DEFINITIONS
The following is a listing of certain abbreviations, acronyms, and other industry terminology that may be used throughout this Form 10-Q.
Measurements:
Barrel: One
barrel of petroleum products that equals 42 U.S. gallons
Mbbls/d: One thousand barrels per day
Bcf: One billion cubic feet of natural gas
Bcf/d: One billion cubic feet of natural gas per day
MMcf/d: One million cubic feet per day
British Thermal Unit (Btu): A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
Tbtu: One trillion British thermal units
Dekatherms (Dth): A unit of energy equal to one million British thermal units
Mdth/d: One
thousand dekatherms per day
MMdth: One million dekatherms or approximately one trillion British thermal units
MMdth/d: One million dekatherms per day
Consolidated Entities:
Caiman II: Caiman Energy II, LLC, (renamed Blue Racer Midstream Holdings, LLC, effective February 2, 2021) a former equity-method investment which is a consolidated entity following our November 2020 acquisition of an additional ownership interest
Cardinal: Cardinal Gas Services, L.L.C.
Gulfstar One: Gulfstar One LLC
Northwest Pipeline: Northwest Pipeline LLC
Transco: Transcontinental Gas Pipe Line Company, LLC
Northeast JV: Ohio Valley Midstream LLC
Partially Owned Entities: Entities in which we do not own a 100 percent ownership interest and which, as of March 31, 2021, we account for as equity-method investments, including principally the following:
Aux Sable: Aux Sable Liquid Products LP
Blue Racer: Blue
Racer Midstream LLC
Discovery: Discovery Producer Services LLC
Gulfstream: Gulfstream Natural Gas System, L.L.C.
Laurel Mountain: Laurel Mountain Midstream, LLC
OPPL: Overland Pass Pipeline Company LLC
RMM: Rocky Mountain Midstream Holdings LLC
Targa Train 7: Targa Train 7 LLC
4
Government and Regulatory:
EPA: Environmental
Protection Agency
Exchange Act, the: Securities and Exchange Act of 1934, as amended
FERC: Federal Energy Regulatory Commission
IRS: Internal Revenue Service
SEC: Securities and Exchange Commission
Other:
EBITDA: Earnings before interest, taxes, depreciation, and amortization
Fractionation: The process by which a mixed stream of natural gas liquids is separated into constituent products, such as ethane, propane, and butane
GAAP: U.S.
generally accepted accounting principles
LNG: Liquefied natural gas; natural gas which has been liquefied at cryogenic temperatures
MVC: Minimum volume commitments
NGLs: Natural gas liquids; natural gas liquids result from natural gas processing and crude oil refining and are used as petrochemical feedstocks, heating fuels, and gasoline additives, among other applications
NGL margins:NGL revenues less any applicable Btu replacement cost, plant fuel, transportation, and fractionation
Net unrealized gain (loss) from derivative instruments, net of taxes of $i2
in 2021 and $i— in 2020
(i9)
i—
Reclassifications
into earnings of net derivative instruments (gain) loss, net of taxes of $i— in 2021 and $i—
in 2020
i2
i—
Pension
and other postretirement benefits:
Net actuarial gain (loss) arising during the year, net of taxes of $i—
in 2021 and $i4 in 2020
i—
(i14)
Amortization
of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit), net of taxes of ($i1) in 2021 and ($i2)
in 2020
i3
i8
Other
comprehensive income (loss)
(i4)
(i6)
Comprehensive
income (loss)
i431
(i576)
Less:
Comprehensive income (loss) attributable to noncontrolling interests
i9
(i53)
Comprehensive
income (loss) attributable to The Williams Companies, Inc.
Adjustments
to reconcile to net cash provided (used) by operating activities:
Depreciation and amortization
i438
i429
Provision
(benefit) for deferred income taxes
i144
(i177)
Equity
(earnings) losses
(i131)
(i22)
Distributions
from unconsolidated affiliates
i176
i169
Impairment
of goodwill (Note 10)
i—
i187
Impairment
of equity-method investments (Note 10)
i—
i938
Amortization
of stock-based awards
i20
i9
Cash
provided (used) by changes in current assets and liabilities:
Accounts receivable
(i59)
i67
Inventories
(i8)
i19
Other
current assets and deferred charges
(i6)
i20
Accounts
payable
i38
(i155)
Accrued
liabilities
(i116)
(i150)
Other,
including changes in noncurrent assets and liabilities
(i16)
i23
Net
cash provided (used) by operating activities
i915
i787
FINANCING
ACTIVITIES:
Proceeds from long-term debt
i897
i1,702
Payments
of long-term debt
(i5)
(i1,518)
Proceeds
from issuance of common stock
i3
i6
Common
dividends paid
(i498)
(i485)
Dividends
and distributions paid to noncontrolling interests
(i54)
(i44)
Contributions
from noncontrolling interests
i2
i2
Payments
for debt issuance costs
(i6)
i—
Other – net
(i13)
(i10)
Net
cash provided (used) by financing activities
i326
(i347)
INVESTING
ACTIVITIES:
Property, plant, and equipment:
Capital expenditures (1)
(i260)
(i306)
Dispositions
– net
(i1)
(i3)
Contributions
in aid of construction
i19
i14
Purchases
of and contributions to equity-method investments
(i14)
(i30)
Other – net
(i1)
(i4)
Net
cash provided (used) by investing activities
(i257)
(i329)
Increase
(decrease) in cash and cash equivalents
i984
i111
Cash
and cash equivalents at beginning of year
i142
i289
Cash
and cash equivalents at end of period
$
i1,126
$
i400
_____________
(1) Increases
to property, plant, and equipment
$
(i263)
$
(i254)
Changes
in related accounts payable and accrued liabilities
i3
(i52)
Capital
expenditures
$
(i260)
$
(i306)
See
accompanying notes.
10
The Williams Companies, Inc.
Notes to Consolidated Financial Statements
(Unaudited)
i
Note
1 – General, Description of Business, and Basis of Presentation
General
Our accompanying interim consolidated financial statements do not include all the notes in our annual financial statements and, therefore, should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2020, in our Annual Report on Form 10-K. The accompanying unaudited financial statements include all normal recurring adjustments and others that, in the opinion of management, are necessary to present fairly our interim financial statements.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the consolidated
financial statements and accompanying notes. Actual results could differ from those estimates.
Unless the context clearly indicates otherwise, references in this report to “Williams,”“we,”“our,”“us,” or like terms refer to The Williams Companies, Inc. and its subsidiaries. Unless the context clearly indicates otherwise, references to “Williams,”“we,”“our,” and “us” include the operations in which we own interests accounted for as equity-method investments that are not consolidated in our financial statements. When we refer to our equity investees by name, we are referring exclusively to their businesses and operations.
Description of Business
We are a Delaware corporation whose common stock
is listed and traded on the New York Stock Exchange. Our operations are located in the United States and are presented within the following reportable segments: Transmission & Gulf of Mexico, Northeast G&P, and West, consistent with the manner in which our chief operating decision maker evaluates performance and allocates resources. All remaining business activities, including our recently acquired upstream operations, as well as corporate activities are included in Other.
Transmission & Gulf of Mexico is comprised of our interstate natural gas pipelines, Transcontinental Gas Pipe Line Company, LLC (Transco) and Northwest Pipeline LLC (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 i51
percent interest in Gulfstar One LLC (Gulfstar One) (a consolidated variable interest entity, or VIE), which is a proprietary floating production system, a i50 percent equity-method investment in Gulfstream Natural Gas System, L.L.C., and a i60
percent equity-method investment in Discovery Producer Services LLC (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 i65 percent interest in Ohio Valley Midstream LLC (Northeast JV) (a consolidated VIE) which operates in West Virginia, Ohio, and Pennsylvania, a i66
percent interest in Cardinal Gas Services, L.L.C. (Cardinal) (a consolidated VIE) which operates in Ohio, a i69 percent equity-method investment in Laurel Mountain Midstream, LLC (Laurel Mountain), a i50
percent equity-method investment in Blue Racer Midstream LLC (Blue Racer) (we previously effectively owned a i29 percent indirect interest in Blue Racer through our i58
percent equity-method investment in Caiman Energy II, LLC (Caiman II) until acquiring a controlling interest in November 2020), and Appalachia Midstream Services, LLC, a wholly owned subsidiary that owns equity-method investments with an approximate average i66 percent interest in multiple gas gathering systems in the Marcellus Shale region (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
/
11
Notes (Continued)
Anadarko, Arkoma, and Permian basins. This segment also includes our natural gas liquid (NGL) and natural gas marketing business, storage facilities, an undivided i50
percent interest in an NGL fractionator near Conway, Kansas, a i50 percent equity-method investment in Overland Pass Pipeline Company LLC, a i50
percent equity-method investment in Rocky Mountain Midstream Holdings LLC (RMM), a i20 percent equity-method investment in Targa Train 7 LLC (Targa Train 7) (a nonconsolidated VIE), and a i15
percent interest in Brazos Permian II, LLC (Brazos Permian II) (a nonconsolidated VIE).
Basis of Presentation
Significant risks and uncertainties
We believe that the carrying value of certain of our property, plant, and equipment and other identifiable intangible assets, notably certain acquired assets accounted for as business combinations between 2012 and 2014, may be in excess of current fair value. However, the carrying value of these assets, in our judgment, continues to be recoverable. It is reasonably possible that future strategic decisions, including transactions such as monetizing non-core assets or contributing assets to new ventures with third parties, as well as unfavorable changes in expected producer activities, could impact our assumptions and ultimately result in impairments of these assets. Such transactions or developments
may also indicate that certain of our equity-method investments have experienced other-than-temporary declines in value, which could result in impairment.
i
Note 2 – Variable Interest Entities
Consolidated VIEs
As of March 31, 2021, we consolidate the following VIEs:
Northeast
JV
We own a i65 percent interest in the Northeast JV, a subsidiary that is a VIE due to certain of our voting rights being disproportionate to our obligation to absorb losses and substantially all of the Northeast JV’s activities being performed on our behalf. We are the primary beneficiary because we have the power to direct the activities that most significantly impact the Northeast JV’s economic performance. The Northeast JV provides midstream services for producers in the Marcellus
Shale and Utica Shale regions. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.
Gulfstar One
We own a i51 percent interest in Gulfstar One, a subsidiary that, due to certain risk-sharing provisions in its customer contracts, is a VIE. Gulfstar One includes
a proprietary floating production system, Gulfstar FPS, and associated pipelines that provide production handling and gathering services in the eastern deepwater Gulf of Mexico. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Gulfstar One’s economic performance.
Cardinal
We own ai66 percent interest in Cardinal, a subsidiary
that provides gathering services for the Utica Shale region and is a VIE due to certain risks shared with customers. We are the primary beneficiary because we have the power to direct the activities that most significantly impact Cardinal’s economic performance. Future expansion activity is expected to be funded with capital contributions from us and the other equity partner on a proportional basis.
/
12
Notes (Continued)
i
The
following table presents amounts included in the Consolidated Balance Sheet that are only for the use or obligation of our consolidated VIEs:
Intangible
assets – net of accumulated amortization
i2,349
i2,376
Regulatory
assets, deferred charges, and other
i15
i15
Accounts payable
(i49)
(i42)
Accrued
liabilities
(i34)
(i34)
Regulatory
liabilities, deferred income, and other
(i287)
(i289)
/
Nonconsolidated
VIEs
Targa Train 7
We own a i20 percent interest in Targa Train 7, which provides fractionation services at Mt. Belvieu and is a VIE due primarily to our limited participating rights as the minority equity holder. At March 31, 2021, the carrying value of our investment in Targa Train 7 was $i50 million.
Our maximum exposure to loss is limited to the carrying value of our investment.
Brazos Permian II
We own a i15 percent interest in Brazos Permian II, which provides gathering and processing services in the Delaware basin and is a VIE due primarily to our limited participating rights as the minority equity holder. During the first quarter of 2020 we recorded an impairment of our equity-method investment in Brazos Permian II. Our maximum exposure
to loss is limited to the carrying value of our investment.
13
Notes (Continued)
i
Note
3 – Revenue Recognition
Revenue by Category
i
The following table presents our revenue disaggregated by major service line:
(1)Revenues
not within the scope of Accounting Standards Codification Topic 606, “Revenue from Contracts with Customers,” consist of leasing revenues associated with our headquarters building and management fees that we receive for certain services we provide to operated equity-method investments, which are reported in Service revenues in the Consolidated Statement of Operations, and amounts associated with our derivative contracts, which are reported in Product sales in the Consolidated Statement of Operations.
Remaining performance obligations primarily include reservation charges on contracted capacity for our gas pipeline firm transportation contracts with customers, storage capacity contracts, long-term contracts containing minimum volume commitments associated with our midstream businesses, and fixed payments associated with offshore production handling. For our interstate natural gas pipeline businesses, remaining performance obligations reflect the rates for such services in our current Federal Energy Regulatory Commission (FERC) tariffs for the life of the related contracts;
however, these rates may change based on future tariffs approved by the FERC and the amount and timing of these changes are not currently known.
Our remaining performance obligations exclude variable consideration, including contracts with variable consideration for which we have elected the practical expedient for consideration recognized in revenue as billed. Certain of our contracts contain evergreen and other renewal provisions for periods beyond the initial term of the contract. The remaining performance obligation amounts as of March 31, 2021, do not consider potential future performance obligations
for which the renewal has not been exercised and exclude contracts with customers for which the underlying facilities have not received FERC authorization to be placed into service. Consideration received prior to March 31, 2021, that will be recognized in future periods is also excluded from our remaining performance obligations and is instead reflected in contract liabilities.
15
Notes (Continued)
i
The
following table presents the amount of the contract liabilities balance expected to be recognized as revenue when performance obligations are satisfied and the transaction price allocated to the remaining performance obligations under certain contracts as of March 31, 2021.
Accounts receivable related to revenues from contracts with customers
$
i1,007
$
i892
Other
accounts receivable
i51
i107
Trade
accounts and other receivables – net
$
i1,058
$
i999
/i
Note
4 – Investing Activities
Impairment of Equity-Method Investments
Impairment of equity-method investments for the three months ended March 31, 2020, includes $i938 million associated with the impairment of equity-method investments (see Note 10 – Fair Value Measurements and Guarantees).
Equity Earnings (Losses)
Equity
earnings (losses) for the three months ended March 31, 2020, includes a $i78 million loss associated with the first-quarter 2020 full impairment of goodwill recognized by our investee RMM, which was allocated entirely to our member interest per the terms of the membership agreement.
/i
Note
5 – Provision (Benefit) for Income Taxes
i
The Provision (benefit) for income taxes includes:
The effective income tax rates for the total provision (benefit) for both the three months ended March 31, 2021 and 2020 are greater than the federal statutory rate, primarily due to the effect of state income taxes.
During the next 12 months, we do not expect ultimate resolution of any unrecognized tax benefit associated with domestic or international matters to have a material impact on our unrecognized tax benefit position.
(Dollars in millions, except per-share amounts; shares in thousands)
Net income (loss) available to common stockholders
$
i425
$
(i518)
Basic
weighted-average shares
i1,214,646
i1,213,019
Effect
of dilutive securities:
Nonvested restricted stock units
i2,565
i—
Diluted
weighted-average shares (1)
i1,217,211
i1,213,019
Earnings
(loss) per common share:
Basic
$
i.35
$
(i.43)
Diluted
$
i.35
$
(i.43)
______________________________
(1)For
the three months ended March 31, 2020, i1.3 million weighted-average nonvested restricted stock units have been excluded from the computation of diluted earnings (loss) per common share as their inclusion would be antidilutive due to our loss available to common stockholders.
The
components of Net periodic benefit cost (credit) other than the Service cost component are included in Other income (expense) – net below Operating income (loss) in the Consolidated Statement of Operations.
During the three months ended March 31, 2021, we contributed $i1
million to our pension plans and $i1 million to our other postretirement benefit plans. We presently anticipate making additional contributions of approximately $i2
million to our pension plans and approximately $i5 million to our other postretirement benefit plans in the remainder of 2021.
i
Note
8 – Debt and Banking Arrangements
Long-Term Debt
Issuances and retirements
On March 2, 2021, we completed a public offering of $i900 million of i2.6
percent senior unsecured notes due 2031.
Commercial Paper Program
At March 31, 2021, inoCommercial paper was outstanding under our $i4
billion commercial paper program.
Letters
of credit under certain bilateral bank agreements
i17
(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.
As disclosed in our Annual Report on Form 10-K filed February 24, 2021, a purported shareholder filed a putative class action lawsuit in the Delaware Court of Chancery challenging our stockholder rights agreement (Rights Agreement). On February 26, 2021, the Delaware Court of Chancery issued a decision which declared the Rights Agreement unenforceable and permanently enjoined the continued operation of the Rights
Agreement, which otherwise would have expired on March 20, 2021.
18
Notes (Continued)
i
AOCI
The following table presents the changes in AOCI by
component, net of income taxes:
Amortization of actuarial (gain) loss and net actuarial loss from settlements included in net periodic benefit cost (credit)
i4
Other
income (expense) – net below Operating income (loss)
Income tax benefit
(i1)
Provision
(benefit) for income taxes
Reclassifications during the period
$
i5
/
19
Notes
(Continued)
i
Note 10 – Fair Value Measurements and Guarantees
i
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)
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.
/
20
Notes (Continued)
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 $i26 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 ino 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 i40
percent during the quarter, including a i26 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 $i187 million as of March 31, 2020, in Impairment of goodwill in the Consolidated Statement of Operations. Our partner’s
$i65 million share of this impairment is reflected within Net income (loss) attributable to noncontrolling interests in the Consolidated Statement of Operations.
21
Notes (Continued)
i
The
following table presents impairments of equity-method investments associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy.
(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 ii17/
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 i5.0x
to i6.2x EBITDA (weighted-average i6.0x). 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 i9.7
percent to i13.5 percent (weighted-average i12.6 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.
/i
Note 11 – 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.
22
Notes (Continued)
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 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 was scheduled to begin June 14, 2021, but the court struck the setting and has not reset it.
Because of the uncertainty around the remaining 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 court permitted the State of Alaska to amend its complaint to add a claim for offsite PFOS/PFOA contamination. The court 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
23
Notes (Continued)
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 $i86
million. The court found that FHRA is not entitled to contractual indemnification from us because FHRA contributed to the sulfolane contamination. On March 23, 2020, the court entered final judgment in the case. Filing deadlines were stayed until May 1, 2020. However, on April 21, 2020, we filed a Notice of Appeal. We also filed post-judgment motions including a Motion for New Trial and a Motion to Alter or Amend the Judgment. These post-trial motions were resolved with 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 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 Chesapeake in causing the alleged royalty underpayments. We believe that the claims asserted are
subject to indemnity obligations owed to us by Chesapeake. Chesapeake has reached a settlement to resolve substantially all Pennsylvania royalty cases pending, which settlement applies to both Chesapeake and us. The settlement does not require any contribution from 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 $i1.48 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
24
Notes (Continued)
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 $i1.48 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 $i1.48 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 originally scheduled trial for May 20 through May 24, 2019; the court struck that setting and reset trial to occur in 2020. All 2020 trial settings were struck due to COVID-19. Trial has been reset
for 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, 2021, we have accrued liabilities totaling $i33 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,
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, 2021, we have accrued liabilities of $i4 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, 2021, we have accrued liabilities totaling $i8 million for these costs.
25
Notes (Continued)
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, 2021, we have accrued environmental liabilities of $i21 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, 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 that 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.
i
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
26
Notes (Continued)
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.
27
Notes (Continued)
i
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.
(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 i2,000 operated wells, in the Wamsutter basin in Wyoming from a supermajor oil and gas company for approximately $i79 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 $i290 million of property, plant, and equipment and $i207 million
of ARO related to this transaction.
/
28
Notes (Continued)
i
The following table reflects the reconciliation
of Modified EBITDA to Net income (loss) as reported in the Consolidated Statement of Operations.
Accretion
expense associated with asset retirement obligations for nonregulated operations
(i10)
(i10)
Depreciation
and amortization expenses
(i438)
(i429)
Impairment
of goodwill
i—
(i187)
Equity
earnings (losses)
i131
i22
Impairment
of equity-method investments
i—
(i938)
Other
investing income (loss) – net
i2
i3
Proportional
Modified EBITDA of equity-method investments
(i225)
(i192)
Interest
expense
(i294)
(i296)
(Provision)
benefit for income taxes
(i141)
i204
Net
income (loss)
$
i435
$
(i570)
/
29
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. 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: 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. 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 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.
30
Management’s Discussion and Analysis (Continued)
Dividends
In March 2021, we paid a regular quarterly dividend of $0.41 per share.
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
31
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.
32
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.
33
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.
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.
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.
34
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 12 – Segment Disclosures of 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 higher 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 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.
Operating
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. Note 12 – 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 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.
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 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 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 Financial Statements.
38
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 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.
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:
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.
40
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.
41
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 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 2021 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 that 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. Our threshold for disclosing material environmental legal proceedings involving a 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,
42
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 such 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 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.
Other litigation
The additional information called for by this Item is provided in Note 9 – 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, 2020, includes risk factors that could materially affect our business, financial condition, or future results. Those Risk Factors have not materially changed.
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 Sellers) 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 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 customary adjustments.
The Purchase
Agreement contains customary (i) representations and warranties, (ii) covenants, including with respect to actions taken prior to the closing, cooperation with respect to regulatory issues, and access to information, and (iii) indemnification provisions. Williams FSG will obtain a customary buyer’s representation and warranty insurance policy. The Purchase Agreement is subject to customary closing conditions, including the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
We have agreed to guarantee the obligations of 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 number of active contracts and transactions of the Companies with counterparties. We anticipate combined volumes from the Companies’ business and our existing natural gas marketing business will exceed 8 Bcf/d, which we believe would be in the top five of North American natural gas marketers.
43
The Purchase Agreement contains certain termination rights, including by mutual written
consent of the parties or if, subject to certain conditions, the closing has not occurred on or before August 26, 2021. We expect closing to occur during the third quarter of 2021.
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.
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45
Exhibit No.
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§ Management contract or compensatory plan or arrangement.
46
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.
