☒ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 2021.
OR
☐ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from __________ to __________.
Commission file number 001-13643
ONEOK, Inc.
(Exact name of registrant as specified in its charter)
Oklahoma
73-1520922
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
100 West Fifth Street,
Tulsa,
OK
74103
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code (918) 588-7000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common stock, par value of $0.01
OKE
New 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. Yes☒ 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). Yes☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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.
Large Accelerated Filer☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐
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). Yes ☐ No ☒
On October 25, 2021, the Company had 445,936,703 shares of common stock outstanding.
As used in this Quarterly Report, references to “we,” “our” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.
The statements in this Quarterly Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “target,” “guidance,” “intend,” “may,” “might,” “outlook,” “plan,” “potential,” “project,” “scheduled,” “should,” “will,” “would” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations “Forward-Looking Statements,” and Part II, Item 1A, “Risk Factors,” in this Quarterly Report and under Part I, Item 1A, “Risk Factors,” in our Annual Report.
INFORMATION AVAILABLE ON OUR WEBSITE
We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, Current Reports on Form 8-K, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Director Independence Guidelines, Corporate Sustainability Report, Response to COVID-19 and the written charters of our Board Committees also are available on our website, and we will provide copies of these documents upon request.
In addition to our filings with the SEC and materials posted on our website, we also use social media platforms as additional channels of distribution to reach public investors. Information contained on our website, posted on our social media accounts, and any corresponding applications, are not incorporated by reference into this report.
Our accompanying unaudited Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC. These statements have been prepared in accordance with GAAP and reflect all adjustments that, in our opinion, are necessary for a fair statement of the results for the interim periods presented. All such adjustments are of a normal recurring nature. The 2020 year-end Consolidated Balance Sheet data was derived from our audited Consolidated Financial Statements but does not include all disclosures required by GAAP. Certain reclassifications have been made in the prior year Consolidated Financial Statements to conform to the current year presentation. These unaudited Consolidated Financial Statements should be read in conjunction with our audited Consolidated Financial Statements in our Annual Report.
Goodwill Impairment Review - We assess our goodwill for impairment at least annually as of July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. At July 1, 2021, we assessed qualitative factors to determine whether it was more likely than not that the fair value of each of our reporting units was less than their carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, costs and overall financial performance), we determined that it was more likely than not that the fair value of each reporting unit was not less than their respective carrying value, that no further testing was necessary and that goodwill was not considered impaired.
Recently Issued Accounting Standards Update - Changes to GAAP are established by the Financial Accounting Standards Board (FASB) in the form of ASUs to the FASB Accounting Standards Codification. We consider the applicability and impact of all ASUs. ASUs not discussed below or in our Annual Report were assessed and determined to be either not applicable or clarifications of ASUs previously issued. Except as discussed below or in our Annual Report, there have been no new accounting pronouncements that have become effective or have been issued that are of significance or potential significance to us.
In January 2021, we adopted ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” which simplifies certain concepts in Topic 740, Income Taxes. The impact of adopting this standard was not material.
B. FAIR VALUE MEASUREMENTS
Determining Fair Value - For our fair value measurements, we utilize market prices, third-party pricing services, present value methods and standard option valuation models to determine the price we would receive from the sale of an asset or the transfer of a liability in an orderly transaction at the measurement date. We measure the fair value of a group of financial assets and liabilities consistent with how a market participant would price the net risk exposure at the measurement date.
Many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists. Our financial commodity derivatives are generally settled through a NYMEX or ICE clearing broker account with daily margin requirements. We validate our valuation inputs with third-party information and settlement prices from other sources, where available.
We compute the fair value of our derivative portfolio by discounting the projected future cash flows from our derivative assets and liabilities to present value using interest-rate yields to calculate present-value discount factors derived from the implied forward LIBOR yield curve. The fair value of our forward-starting interest-rate swaps is determined using financial models that incorporate the implied forward LIBOR yield curve for the same period as the future interest-rate swap settlements. We consider current market data in evaluating counterparties’, as well as our own, nonperformance risk, net of collateral, by using counterparty-specific bond yields. Although we use our best estimates to determine the fair value of the derivative contracts we have executed, the ultimate market prices realized could differ materially from our estimates.
Fair Value Hierarchy - At each balance sheet date, we utilize a fair value hierarchy to classify fair value amounts recognized or disclosed in our financial statements based on the observability of inputs used to estimate such fair value. The levels of the hierarchy are described below:
•Level 1 - fair value measurements are based on unadjusted quoted prices for identical securities in active markets. These balances are composed predominantly of exchange-traded derivative contracts for natural gas and crude oil.
•Level 2 - fair value measurements are based on significant observable pricing inputs, including quoted prices for similar assets and liabilities in active markets and inputs from third-party pricing services supported with corroborative evidence. These balances are composed of over-the-counter interest-rate derivatives.
•Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs, including internally developed commodity price curves that incorporate market data from broker quotes and third-party pricing services. These balances are composed predominantly of exchange-cleared and over-the-counter derivatives to hedge NGL price risk and natural gas basis risk between various transaction locations and the NYMEX Henry Hub. Our commodity derivatives are generally valued using forward quotes provided by third-party pricing services that are validated with other market data. We believe any measurement uncertainty at September 30, 2021, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as our derivatives are primarily accounted for as hedges.
Determining the appropriate classification of our fair value measurements within the fair value hierarchy requires management’s judgment regarding the degree to which market data is observable or corroborated by observable market data. We categorize derivatives for which fair value is determined using multiple inputs within a single level, based on the lowest level input that is significant to the fair value measurement in its entirety.
Recurring Fair Value Measurements - The following tables set forth our recurring fair value measurements for the periods indicated:
September 30, 2021
Level 1
Level 2
Level 3
Total - Gross
Netting (a)
Total - Net
(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts
$
78,930
$
—
$
430,855
$
509,785
$
(509,785)
$
—
Total derivative assets
$
78,930
$
—
$
430,855
$
509,785
$
(509,785)
$
—
Derivative liabilities
Commodity contracts
Financial contracts
$
(201,124)
$
—
$
(598,063)
$
(799,187)
$
799,187
$
—
Interest-rate contracts
—
(145,591)
—
(145,591)
—
(145,591)
Total derivative liabilities
$
(201,124)
$
(145,591)
$
(598,063)
$
(944,778)
$
799,187
$
(145,591)
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At September 30, 2021, we held no cash and posted $319.2 million of cash with various counterparties, including $289.4 million of cash collateral that is offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $29.8 million of cash collateral in excess of derivative net liability positions is included in other current assets in our Consolidated Balance Sheet.
December 31, 2020
Level 1
Level 2
Level 3
Total - Gross
Netting (a)
Total - Net
(Thousands of dollars)
Derivative assets
Commodity contracts
Financial contracts
$
6,697
$
—
$
103,801
$
110,498
$
(110,498)
$
—
Total derivative assets
$
6,697
$
—
$
103,801
$
110,498
$
(110,498)
$
—
Derivative liabilities
Commodity contracts
Financial contracts
$
(10,489)
$
—
$
(135,122)
$
(145,611)
$
145,611
$
—
Interest-rate contracts
—
(203,407)
—
(203,407)
—
(203,407)
Total derivative liabilities
$
(10,489)
$
(203,407)
$
(135,122)
$
(349,018)
$
145,611
$
(203,407)
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheet on a net basis. We net derivative assets and liabilities when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us. At December 31, 2020, we held no cash and posted $63.1 million of cash with various counterparties, including $35.1 million of cash collateral that is offsetting derivative net liability positions under master-netting arrangements in the table above. The remaining $28.0 million of cash collateral in excess of derivative net liability positions is included in other current assets in our Consolidated Balance Sheet.
The following table sets forth a reconciliation of our Level 3 fair value measurements for the periods indicated:
Three Months Ended
Nine Months Ended
September 30,
September 30,
Derivative Assets (Liabilities)
2021
2020
2021
2020
(Thousands of dollars)
Net assets (liabilities) at beginning of period
$
(121,750)
$
5,583
$
(31,321)
$
30,772
Total changes in fair value:
Settlements included in net income (a)
46,797
(6,194)
28,028
(29,471)
New Level 3 derivatives included in other comprehensive loss (b)
(23,151)
(2,033)
(129,805)
(5,140)
Unrealized change included in other comprehensive loss (b)
(69,104)
(2,700)
(34,110)
(1,505)
Net liabilities at end of period
$
(167,208)
$
(5,344)
$
(167,208)
$
(5,344)
(a) - Included in commodity sales revenues/cost of sales and fuel in our Consolidated Statements of Income.
(b) - Included in change in fair value of derivatives in our Consolidated Statements of Comprehensive Income.
During the three and nine months ended September 30, 2021 and 2020, there were no transfers in or out of Level 3 of the fair value hierarchy.
Other Financial Instruments - The approximate fair value of cash and cash equivalents, accounts receivable, accounts payable and short-term borrowings is equal to book value due to the short-term nature of these items. Our cash and cash equivalents are composed of bank and money market accounts and are classified as Level 1. Our short-term borrowings are classified as Level 2 since the estimated fair value of the short-term borrowings can be determined using information available in the commercial paper market.
The estimated fair value of our consolidated long-term debt, including current maturities, was $16.5 billion and $16.3 billion at September 30, 2021, and December 31, 2020, respectively. The book value of our consolidated long-term debt, including current maturities, was $14.2 billion at September 30, 2021, and December 31, 2020. The estimated fair value of the aggregate long-term debt outstanding was determined using quoted market prices for similar issues with similar terms and maturities. The estimated fair value of our consolidated long-term debt is classified as Level 2.
C. RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES
Risk-management Activities - We are sensitive to changes in natural gas, crude oil and NGL prices, principally as a result of contractual terms under which these commodities are processed, purchased and sold. We are also subject to the risk of interest-rate fluctuation in the normal course of business. We use physical-forward purchases and sales and financial derivatives to secure a certain price for a portion of our natural gas, condensate and NGL products; to reduce our exposure to commodity price and interest-rate fluctuations; and to achieve more predictable cash flows. We follow established policies and procedures to assess risk and approve, monitor and report our risk-management activities. We have not used these instruments for trading purposes.
Commodity price risk - Commodity price risk refers to the risk of loss in cash flows and future earnings arising from adverse changes in the price of natural gas, NGLs and condensate. We may use the following commodity derivative instruments to reduce the near-term commodity price risk associated with a portion of the forecasted sales of these commodities:
•Futures contracts - Standardized contracts to purchase or sell natural gas and crude oil for future delivery or settlement under the provisions of exchange regulations;
•Forward contracts - Nonstandardized commitments between two parties to purchase or sell natural gas, crude oil or NGLs for future physical delivery. These contracts are typically nontransferable and can only be canceled with the consent of both parties;
•Swaps - Exchange of one or more payments based on the value of one or more commodities. These instruments transfer the financial risk associated with a future change in value between the counterparties of the transaction, without also conveying ownership interest in the asset or liability; and
•Options - Contractual agreements that give the holder the right, but not the obligation, to buy or sell a fixed quantity of a commodity at a fixed price within a specified period of time. Options may either be standardized and exchange-traded or customized and nonexchange-traded.
We may also use other instruments, including collars, to mitigate commodity price risk. A collar is a combination of a purchased put option and a sold call option, which places a floor and a ceiling price for commodity sales being hedged.
In our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our fee with POP contracts. Under certain fee with POP contracts, our fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. In certain commodity price environments, our contractual fees on these fee with POP contracts may decrease, which would impact the average fee rate in our Natural Gas Gathering and Processing segment. We also are exposed to basis risk between the various production and market locations where we buy and sell commodities. As part of our hedging strategy, we use the previously described commodity derivative financial instruments and physical-forward contracts to reduce the impact of price fluctuations related to natural gas, NGLs and condensate.
In our Natural Gas Liquids segment, we are primarily exposed to commodity price risk resulting from the relative values of the various NGL products to each other, the value of NGLs in storage and the relative value of NGLs to natural gas. We are also exposed to location price differential risk as a result of the relative value of NGL purchases at one location and sales at another location, primarily related to our optimization and marketing activities. As part of our hedging strategy, we utilize physical-forward contracts and commodity derivative financial instruments to reduce the impact of price fluctuations related to NGLs.
In our Natural Gas Pipelines segment, we are primarily exposed to commodity price risk on our intrastate pipelines because they consume natural gas in operations and retain natural gas from our customers for operations or as part of our fee for services provided. When the amount consumed in operations differs from the amount provided by our customers, our pipelines must buy or sell natural gas, or store or use natural gas inventory, which can expose this segment to commodity price risk depending on the regulatory treatment for this activity. To the extent that commodity price risk in our Natural Gas Pipelines segment is not mitigated by fuel cost-recovery mechanisms, we may use physical-forward sales or purchases to reduce the impact of natural gas price fluctuations. At September 30, 2021, and December 31, 2020, there were no financial derivative instruments with respect to our natural gas pipeline operations.
Interest-rate risk - We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts.
At September 30, 2021, and December 31, 2020, we had forward-starting interest-rate swaps with notional amounts totaling $1.1 billion to hedge the variability of interest payments on a portion of our forecasted debt issuances. All of our interest-rate swaps are designated as cash flow hedges.
Accounting Treatment - Our accounting treatment of derivative instruments is consistent with that disclosed in Note A of the Notes to Consolidated Financial Statements in our Annual Report.
Fair Values of Derivative Instruments - See Note B for a discussion of the inputs associated with our fair value measurements. The following table sets forth the fair values of our derivative instruments presented on a gross basis for the periods indicated:
September 30, 2021
December 31, 2020
Location in our Consolidated Balance Sheets
Assets
(Liabilities)
Assets
(Liabilities)
Derivatives designated as hedging instruments
(Thousands of dollars)
Commodity contracts (a)
Financial contracts (b)
$
503,132
$
(792,548)
$
107,461
$
(142,573)
Interest-rate contracts
Other current liabilities
—
(91,081)
—
—
Other deferred credits
—
(54,510)
—
(203,407)
Total derivatives designated as hedging instruments
503,132
(938,139)
107,461
(345,980)
Derivatives not designated as hedging instruments
Commodity contracts (a)
Financial contracts (b)
6,653
(6,639)
3,037
(3,038)
Total derivatives not designated as hedging instruments
6,653
(6,639)
3,037
(3,038)
Total derivatives
$
509,785
$
(944,778)
$
110,498
$
(349,018)
(a) - Derivative assets and liabilities are presented in our Consolidated Balance Sheets on a net basis when a legally enforceable master-netting arrangement exists between the counterparty to a derivative contract and us.
(b) - At September 30, 2021, and December 31, 2020, our derivative net liability positions under master-netting arrangements for financial contracts were fully offset by cash collateral of $289.4 million and $35.1 million, respectively.
Notional Quantities for Derivative Instruments - The following table sets forth the notional quantities for derivative instruments held for the periods indicated:
September 30, 2021
December 31, 2020
Contract Type
Net Purchased/Payor (Sold/Receiver)
Derivatives designated as hedging instruments: (a)
Cash flow hedges
Fixed price
- Natural gas (Bcf)
Futures
(38.1)
(43.3)
- Crude oil and NGLs (MMBbl)
Futures
(9.1)
(4.6)
Basis
- Natural gas (Bcf)
Futures
(35.8)
(43.3)
Interest-rate contracts (Billions of dollars)
Swaps
$
1.1
$
1.1
(a) - Notional amounts for derivatives not designated as hedging instruments are excluded from the table above due to fully offsetting notional quantities of 0.2 MMBbl and 0.8 MMBbl for NGLs fixed priced derivative instruments at September 30, 2021, and December 31, 2020, respectively.
Cash Flow Hedges - The following table sets forth the unrealized change in fair value of cash flow hedges in other comprehensive loss for the periods indicated:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2021
2020
2021
2020
(Thousands of dollars)
Commodity contracts
$
(171,665)
$
(29,667)
$
(410,572)
$
18,472
Interest-rate contracts
800
9,213
57,816
(237,200)
Total unrealized change in fair value of cash flow hedges in other comprehensive loss
The following table sets forth the effect of cash flow hedges on net income for the periods indicated:
Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Loss into Net Income
Three Months Ended
Nine Months Ended
September 30,
September 30,
2021
2020
2021
2020
(Thousands of dollars)
Commodity contracts
Commodity sales revenues
$
(223,741)
$
2,167
$
(439,421)
$
100,304
Cost of sales and fuel
147,360
(1,568)
283,153
(31,057)
Interest-rate contracts (a)
Interest expense
(9,902)
(8,998)
(29,483)
(83,817)
Total change in fair value of cash flow hedges reclassified from accumulated other comprehensive loss into net income on derivatives
$
(86,283)
$
(8,399)
$
(185,751)
$
(14,570)
(a) - The nine months ended September 30, 2020, include a loss of $48.3 million on the settlement of $1.3 billion of interest-rate swaps used to hedge our LIBOR-based interest payments.
Credit Risk - We monitor the creditworthiness of our counterparties and compliance with policies and limits established by our Risk Oversight and Strategy Committee. We maintain credit policies with regard to our counterparties that we believe minimize overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings, bond yields and credit default swap rates), collateral requirements under certain circumstances and the use of standardized master-netting agreements that allow us to net the positive and negative exposures associated with a single counterparty. We use internally developed credit ratings for counterparties that do not have a credit rating.
Our financial commodity derivatives are generally settled through a NYMEX or ICE clearing broker account with daily margin requirements. However, we may enter into financial derivative instruments that contain provisions that require us to maintain an investment-grade credit rating from S&P, Fitch and/or Moody’s. If our credit ratings on our senior unsecured long-term debt were to decline below investment grade, the counterparties to the derivative instruments could request collateralization on derivative instruments in net liability positions. There were no financial derivative instruments with contingent features related to credit risk at September 30, 2021.
The counterparties to our derivative contracts typically consist of major energy companies, financial institutions and commercial and industrial end users. This concentration of counterparties may affect our overall exposure to credit risk, either positively or negatively, in that the counterparties may be affected similarly by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, we do not anticipate a material adverse effect on our financial position or results of operations as a result of counterparty nonperformance.
At September 30, 2021, the credit exposure from our derivative assets is with investment-grade companies in the financial services sector.
The following table sets forth our consolidated debt for the periods indicated:
September 30, 2021
December 31, 2020
(Thousands of dollars)
Commercial paper outstanding
$
—
$
—
Senior unsecured obligations:
$700,000 at 4.25% due February 2022
536,107
541,877
$900,000 at 3.375% due October 2022
895,814
895,814
$425,000 at 5.0% due September 2023
425,000
425,000
$500,000 at 7.5% due September 2023
500,000
500,000
$500,000 at 2.75% due September 2024
500,000
500,000
$500,000 at 4.9% due March 2025
500,000
500,000
$400,000 at 2.2% due September 2025
387,000
387,000
$600,000 at 5.85% due January 2026
600,000
600,000
$500,000 at 4.0% due July 2027
500,000
500,000
$800,000 at 4.55% due July 2028
800,000
800,000
$100,000 at 6.875% due September 2028
100,000
100,000
$700,000 at 4.35% due March 2029
700,000
700,000
$750,000 at 3.4% due September 2029
714,251
714,251
$850,000 at 3.1% due March 2030
780,093
780,093
$600,000 at 6.35% due January 2031
600,000
600,000
$400,000 at 6.0% due June 2035
400,000
400,000
$600,000 at 6.65% due October 2036
600,000
600,000
$600,000 at 6.85% due October 2037
600,000
600,000
$650,000 at 6.125% due February 2041
650,000
650,000
$400,000 at 6.2% due September 2043
400,000
400,000
$700,000 at 4.95% due July 2047
689,006
689,006
$1,000,000 at 5.2% due July 2048
1,000,000
1,000,000
$750,000 at 4.45% due September 2049
672,530
713,676
$500,000 at 4.5% due March 2050
443,015
451,270
$300,000 at 7.15% due January 2051
300,000
300,000
Guardian Pipeline
Weighted average 7.85% due December 2022
—
13,657
Total debt
14,292,816
14,361,644
Unamortized portion of terminated swaps
12,025
13,314
Unamortized debt issuance costs and discounts
(128,267)
(138,887)
Current maturities of long-term debt
(536,107)
(7,650)
Long-term debt
$
13,640,467
$
14,228,421
$2.5 Billion Credit Agreement - Our $2.5 Billion Credit Agreement is a revolving credit facility and contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our $2.5 Billion Credit Agreement, adjusted for all noncash charges and increased for projected EBITDA from certain lender-approved capital expansion projects) of no more than 5.0 to 1 at September 30, 2021. At September 30, 2021, we had no outstanding borrowings, our ratio of indebtedness to adjusted EBITDA was 4.3 to 1, and we were in compliance with all covenants under our $2.5 Billion Credit Agreement.
Debt Repayments - On November 1, 2021, we redeemed the remaining $536.1 million of our $700 million, 4.25% senior notes due February 2022 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand and short-term borrowings. As of October 31, 2021, we had $150 million of short-term borrowings outstanding.
In June 2021, we repaid the remaining $11.7 million of Guardian Pipeline’s senior notes due December 2022 with cash on hand.
In the first quarter 2021, we repurchased in the open market outstanding principal of certain of our senior notes in the amount of $55.2 million for an aggregate repurchase price of $54.6 million with cash on hand.
Debt Guarantees - We, ONEOK Partners and the Intermediate Partnership have cross guarantees in place for our and ONEOK Partners’ indebtedness.
E. EQUITY
Dividends -Holders of our common stock share equally in any dividend declared by our Board of Directors, subject to the rights of the holders of outstanding Series E Preferred Stock. Dividends paid on our common stock in February 2021, May 2021 and August 2021 were $0.935 per share. A dividend of $0.935 per share was declared for shareholders of record at the close of business on November 1, 2021, payable November 15, 2021.
Our Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year. We paid dividends for the Series E Preferred Stock of $0.3 million in February 2021, May 2021 and August 2021. Dividends totaling $0.3 million were declared for the Series E Preferred Stock and are payable November 15, 2021.
F. ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table sets forth the balance in accumulated other comprehensive loss for the period indicated:
Risk- Management Assets/Liabilities (a)
Retirement and Other Postretirement Benefit Plan Obligations (a) (b)
Risk- Management Assets/Liabilities of Unconsolidated Affiliates (a)
Accumulated Other Comprehensive Loss (a)
(Thousands of dollars)
January 1, 2021
$
(377,446)
$
(157,635)
$
(16,368)
$
(551,449)
Other comprehensive income (loss) before reclassifications
(271,622)
(118)
3,350
(268,390)
Amounts reclassified to net income (c)
143,029
13,541
1,433
158,003
Other comprehensive income (loss)
(128,593)
13,423
4,783
(110,387)
September 30, 2021
$
(506,039)
$
(144,212)
$
(11,585)
$
(661,836)
(a) - All amounts are presented net of tax.
(b) - Includes amounts related to supplemental executive retirement plan.
(c) - See Note C for details of amounts reclassified to net income for risk-management assets/liabilities and Note H for retirement and other postretirement benefit plan obligations.
The following table sets forth information about the balance of accumulated other comprehensive loss at September 30, 2021, representing unrealized losses related to risk-management assets and liabilities:
Risk- Management Assets/Liabilities (a)
(Thousands of dollars)
Commodity derivative instruments expected to be realized within the next 27 months (b)
$
(223,117)
Settled interest-rate swaps to be recognized over the life of the long-term, fixed-rate debt (c)
(170,817)
Interest-rate swaps with future settlement dates expected to be amortized over the life of long-term debt
(112,105)
Accumulated other comprehensive loss at September 30, 2021
$
(506,039)
(a) - All amounts are presented net of tax.
(b) - Based on commodity prices on September 30, 2021, we expect $206.4 million in net losses, net of tax, over the next 12 months.
(c) - We expect net losses of $30.1 million, net of tax, will be reclassified into earnings during the next 12 months.
The remaining amounts in accumulated other comprehensive loss relate primarily to our retirement and other postretirement benefit plan obligations, which are expected to be amortized over the average remaining service period of employees participating in these plans.
The following table sets forth the components of net periodic benefit cost for our retirement and other postretirement benefit plans for the periods indicated:
Retirement Benefits
Other Postretirement Benefits
Three Months Ended
Three Months Ended
September 30,
September 30,
2021
2020
2021
2020
(Thousands of dollars)
Components of net periodic benefit cost (income)
Service cost
$
2,076
$
2,036
$
105
$
115
Interest cost
4,220
4,574
363
442
Expected return on plan assets
(6,269)
(6,232)
(340)
(722)
Amortization of prior service cost (a)
28
28
—
—
Amortization of net loss (a)
4,913
4,571
921
1
Net periodic benefit cost (income)
$
4,968
$
4,977
$
1,049
$
(164)
(a) - These components of net periodic benefit cost (income) are recognized in accumulated other comprehensive loss and are reclassified to other expense in our Consolidated Statements of Income, with related income tax benefits of $1.3 million and $1.1 million reclassified to income taxes for the three months ended September 30, 2021 and 2020, respectively.
Retirement Benefits
Other Postretirement Benefits
Nine Months Ended
Nine Months Ended
September 30,
September 30,
2021
2020
2021
2020
(Thousands of dollars)
Components of net periodic benefit cost (income)
Service cost
$
6,228
$
6,108
$
315
$
345
Interest cost
12,660
13,722
1,089
1,326
Expected return on plan assets
(18,807)
(18,696)
(1,020)
(2,166)
Amortization of prior service cost (a)
84
84
—
—
Amortization of net loss (a)
14,739
13,713
2,763
3
Net periodic benefit cost (income)
$
14,904
$
14,931
$
3,147
$
(492)
(a) - These components of net periodic benefit cost (income) are recognized in accumulated other comprehensive loss and are reclassified to other expense in our Consolidated Statements of Income, with related income tax benefits of $4.0 million and $3.2 million reclassified to income taxes for the nine months ended September 30, 2021 and 2020, respectively.
I. UNCONSOLIDATED AFFILIATES
Equity in Net Earnings from Investments and Impairments - The following table sets forth our equity in net earnings from investments for the periods indicated:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2021
2020
2021
2020
(Thousands of dollars)
Northern Border Pipeline
$
14,634
$
22,037
$
47,459
$
57,028
Overland Pass Pipeline
5,241
8,007
12,952
30,090
Roadrunner
8,056
8,033
23,407
21,275
Other
642
(31)
3,795
(392)
Equity in net earnings from investments
$
28,573
$
38,046
$
87,613
$
108,001
Impairment of equity investments
$
—
$
—
$
—
$
(37,730)
In the first quarter 2020, we incurred a noncash impairment charge of $30.5 million related to our 10.2% investment in Venice Energy Services Company in our Natural Gas Gathering and Processing segment, which includes $22.3 million related to
equity-method goodwill, and a $7.2 million noncash impairment charge related to our 50% investment in Chisholm Pipeline Company in our Natural Gas Liquids segment.
We incurred expenses in transactions with unconsolidated affiliates of $16.2 million and $35.8 million for the three months ended September 30, 2021 and 2020, respectively, and $44.2 million and $108.4 million for the nine months ended September 30, 2021 and 2020, respectively, primarily related to Northern Border Pipeline and Overland Pass Pipeline. Revenue earned and accounts receivable from, and accounts payable to, our equity-method investees were not material.
We have an operating agreement with Roadrunner that provides for reimbursement or payment to us for management services and certain operating costs, which are included in operating income in our Consolidated Statements of Income.
J. COMMITMENTS AND CONTINGENCIES
Environmental Matters and Pipeline Safety -The operation of pipelines, plants and other facilities for the gathering, processing, fractionation, transportation and storage of natural gas, NGLs, condensate and other products is subject to numerous and complex laws and regulations pertaining to health, safety and the environment. As an owner and/or operator of these facilities, we must comply with laws and regulations that relate to air and water quality, hazardous and solid waste management and disposal, cultural resource protection and other environmental and safety matters. The cost of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with these laws, regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements and the issuance of injunctions or restrictions on operation or construction. Management does not believe that, based on currently known information, a material risk of noncompliance with these laws and regulations exists that will affect adversely our consolidated results of operations, financial condition or cash flows.
Legal Proceedings - We are a party to various legal proceedings that have arisen in the normal course of our operations. While the results of these proceedings cannot be predicted with certainty, we believe the reasonably possible losses from such proceedings, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
K. REVENUES
Accounting Policies - Many of the contract types described within Note A of the Notes to Consolidated Financial Statement in our Annual Report contain additional fees or charges payable by customers for nonperformance (e.g., minimum volume commitments or product specifications), which are considered to be variable consideration. These fees and charges are not recorded until it is probable that a significant reversal of the associated revenue will not occur.
Contract Assets and Contract Liabilities - Our contract asset balances at the beginning and end of the period primarily relate to our firm service transportation contracts with tiered rates, which are not material. The following table sets forth the balances in contract liabilities for the periods indicated:
Contract Liabilities
(Millions of dollars)
Balance at December 31, 2020 (a)
$
41.4
Revenue recognized included in beginning balance
(22.8)
Net additions
33.9
Balance at September 30, 2021 (b)
$
52.5
(a) - Contract liabilities of $23.7 million and $17.7 million are included in other current liabilities and other deferred credits, respectively, in our Consolidated Balance Sheet.
(b) - Contract liabilities of $35.8 million and $16.7 million are included in other current liabilities and other deferred credits, respectively, in our Consolidated Balance Sheet.
Receivables from Customers and Revenue Disaggregation - Substantially all of the balances in accounts receivable on our Consolidated Balance Sheets at September 30, 2021, and December 31, 2020, relate to customer receivables. Revenues sources are disaggregated in Note L.
Transaction Price Allocated to Unsatisfied Performance Obligations - We do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) variable consideration on contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.
The following table presents aggregate value allocated to unsatisfied performance obligations as of September 30, 2021, and the amounts we expect to recognize in revenue in future periods, related primarily to firm transportation and storage contracts with remaining contract terms ranging from one month to 23 years:
Expected Period of Recognition in Revenue
(Millions of dollars)
Remainder of 2021
$
93.4
2022
327.0
2023
282.2
2024
240.7
2025 and beyond
953.9
Total estimated transaction price allocated to unsatisfied performance obligations
$
1,897.2
The table above excludes variable consideration allocated entirely to wholly unsatisfied performance obligations, wholly unsatisfied promises to transfer distinct goods or services that are part of a single performance obligation and consideration we determine to be fully constrained. The amounts we determined to be fully constrained relate to future sales obligations under long-term sales contracts where the transaction price is not known and minimum volume agreements, which we consider to be fully constrained until invoiced.
L. SEGMENTS
Segment Descriptions - Our operations are divided into three reportable business segments as follows:
• our Natural Gas Gathering and Processing segment gathers, treats and processes natural gas;
• our Natural Gas Liquids segment gathers, treats, fractionates and transports NGLs and stores, markets and distributes NGL products; and
• our Natural Gas Pipelines segment transports and stores natural gas via regulated intrastate and interstate natural gas transmission pipelines and natural gas storage facilities.
Other and eliminations consist of corporate costs, the operating and leasing activities of our headquarters building and related parking facility and eliminations necessary to reconcile our reportable segments to our Consolidated Financial Statements.
Accounting Policies - The accounting policies of the segments are described in Note A of the Notes to Consolidated Financial Statements in our Annual Report.
Operating Segment Information - The following tables set forth certain selected financial information for our operating segments for the periods indicated:
Three Months Ended September 30, 2021
Natural Gas Gathering and Processing
Natural Gas Liquids (a)
Natural Gas Pipelines (b)
Total Segments
(Thousands of dollars)
NGL and condensate sales
$
815,993
$
3,853,078
$
—
$
4,669,071
Residue natural gas sales
370,801
—
19
370,820
Gathering, processing and exchange services revenue
35,395
133,574
—
168,969
Transportation and storage revenue
—
40,465
120,294
160,759
Other
6,294
2,499
167
8,960
Total revenues (c)
1,228,483
4,029,616
120,480
5,378,579
Cost of sales and fuel (exclusive of depreciation and operating costs)
(913,931)
(3,377,903)
(344)
(4,292,178)
Operating costs
(95,210)
(128,809)
(41,020)
(265,039)
Equity in net earnings from investments
499
5,384
22,690
28,573
Noncash compensation expense and other
9,816
3,871
920
14,607
Segment adjusted EBITDA
$
229,657
$
532,159
$
102,726
$
864,542
Depreciation and amortization
$
(63,750)
$
(74,986)
$
(14,821)
$
(153,557)
Capital expenditures
$
80,839
$
53,778
$
24,587
$
159,204
(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $618.8 million, of which $567.7 million related to revenues within the segment, and cost of sales and fuel of $160.0 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $72.4 million and cost of sales and fuel of $3.9 million.
(c) - Intersegment revenues are primarily commodity sales which are based on the contracted selling price that is generally index-based and settled monthly, and for the Natural Gas Gathering and Processing segment totaled $837.7 million. Intersegment revenues for the Natural Gas Liquids and Natural Gas Pipelines segments were not material.
Three Months Ended September 30, 2021
Total Segments
Other and Eliminations
Total
(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales
$
4,669,071
$
(838,279)
$
3,830,792
Residue natural gas sales
370,820
—
370,820
Gathering, processing and exchange services revenue
168,969
—
168,969
Transportation and storage revenue
160,759
(3,500)
157,259
Other
8,960
(625)
8,335
Total revenues (a)
$
5,378,579
$
(842,404)
$
4,536,175
Cost of sales and fuel (exclusive of depreciation and operating costs)
$
(4,292,178)
$
843,051
$
(3,449,127)
Operating costs
$
(265,039)
$
(78)
$
(265,117)
Depreciation and amortization
$
(153,557)
$
(985)
$
(154,542)
Equity in net earnings from investments
$
28,573
$
—
$
28,573
Capital expenditures
$
159,204
$
7,003
$
166,207
(a) - Noncustomer revenue for the three months ended September 30, 2021, totaled $(178.7) millionrelated primarily to losses from derivatives on commodity contracts.
Gathering, processing and exchange services revenue
36,459
132,210
—
168,669
Transportation and storage revenue
—
39,774
113,047
152,821
Other
4,644
2,110
251
7,005
Total revenues (c)
459,405
1,832,217
117,296
2,408,918
Cost of sales and fuel (exclusive of depreciation and operating costs)
(207,519)
(1,289,667)
(3,389)
(1,500,575)
Operating costs
(69,351)
(101,223)
(34,567)
(205,141)
Equity in net earnings (loss) from investments
(42)
8,018
30,070
38,046
Noncash compensation expense and other
655
1,898
427
2,980
Segment adjusted EBITDA
$
183,148
$
451,243
$
109,837
$
744,228
Depreciation and amortization
$
(66,459)
$
(71,534)
$
(14,243)
$
(152,236)
Capital expenditures
$
63,030
$
298,891
$
12,978
$
374,899
(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $541.7 million, of which $495.4 million related to revenues within the segment, and cost of sales and fuel of $137.5 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $71.8 million and cost of sales and fuel of $9.6 million.
(c) - Intersegment revenues are primarily commodity sales which are based on the contracted selling price that is generally index-based and settled monthly, and for the Natural Gas Gathering and Processing segment totaled $235.6 million. Intersegment revenues for the Natural Gas Liquids and Natural Gas Pipelines segments were not material.
Three Months Ended September 30, 2020
Total Segments
Other and Eliminations
Total
(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales
$
1,897,933
$
(224,731)
$
1,673,202
Residue natural gas sales
182,490
(5,897)
176,593
Gathering, processing and exchange services revenue
168,669
—
168,669
Transportation and storage revenue
152,821
(3,597)
149,224
Other
7,005
(429)
6,576
Total revenues (a)
$
2,408,918
$
(234,654)
$
2,174,264
Cost of sales and fuel (exclusive of depreciation and operating costs)
$
(1,500,575)
$
234,901
$
(1,265,674)
Operating costs
$
(205,141)
$
212
$
(204,929)
Depreciation and amortization
$
(152,236)
$
(1,009)
$
(153,245)
Equity in net earnings from investments
$
38,046
$
—
$
38,046
Capital expenditures
$
374,899
$
5,143
$
380,042
(a) - Noncustomer revenue for the three months ended September 30, 2020, totaled $4.0 millionrelated primarily to gains from derivatives on commodity contracts.
Gathering, processing and exchange services revenue
101,221
376,429
—
477,650
Transportation and storage revenue
—
127,057
365,578
492,635
Other
15,422
38,161
682
54,265
Total revenues (c)
2,931,676
9,639,159
481,738
13,052,573
Cost of sales and fuel (exclusive of depreciation and operating costs)
(2,019,723)
(7,838,141)
(10,901)
(9,868,765)
Operating costs
(266,237)
(382,012)
(121,843)
(770,092)
Equity in net earnings from investments
2,669
14,078
70,866
87,613
Noncash compensation expense and other
15,254
14,994
3,737
33,985
Segment adjusted EBITDA
$
663,639
$
1,448,078
$
423,597
$
2,535,314
Depreciation and amortization
$
(198,050)
$
(223,679)
$
(43,786)
$
(465,515)
Investments in unconsolidated affiliates
$
25,734
$
417,573
$
353,926
$
797,233
Total assets
$
6,725,753
$
14,898,568
$
2,129,406
$
23,753,727
Capital expenditures
$
177,362
$
225,766
$
73,540
$
476,668
(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of $1.8 billion, of which $1.6 billion related to revenues within the segment, and cost of sales and fuel of $449.1 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $323.2 million and cost of sales and fuel of $20.5 million.
(c) - Intersegment revenues are primarily commodity sales which are based on the contracted selling price that is generally index-based and settled monthly, and for the Natural Gas Gathering and Processing segment totaled $1.9 billion. Intersegment revenues for the Natural Gas Liquids and Natural Gas Pipelines segments were not material.
Nine Months Ended September 30, 2021
Total Segments
Other and Eliminations
Total
(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales
$
10,971,695
$
(1,920,483)
$
9,051,212
Residue natural gas sales
1,056,328
—
1,056,328
Gathering, processing and exchange services revenue
477,650
—
477,650
Transportation and storage revenue
492,635
(10,541)
482,094
Other
54,265
(1,731)
52,534
Total revenues (a)
$
13,052,573
$
(1,932,755)
$
11,119,818
Cost of sales and fuel (exclusive of depreciation and operating costs)
$
(9,868,765)
$
1,931,149
$
(7,937,616)
Operating costs
$
(770,092)
$
(881)
$
(770,973)
Depreciation and amortization
$
(465,515)
$
(3,068)
$
(468,583)
Equity in net earnings from investments
$
87,613
$
—
$
87,613
Investments in unconsolidated affiliates
$
797,233
$
—
$
797,233
Total assets
$
23,753,727
$
118,604
$
23,872,331
Capital expenditures
$
476,668
$
13,661
$
490,329
(a) - Noncustomer revenue for the nine months ended September 30, 2021, totaled $(386.9) millionrelated primarily to losses from derivatives on commodity contracts.
Gathering, processing and exchange services revenue
110,345
370,920
—
481,265
Transportation and storage revenue
—
131,410
353,188
484,598
Other
11,106
6,779
916
18,801
Total revenues (c)
1,209,194
4,938,523
360,137
6,507,854
Cost of sales and fuel (exclusive of depreciation and operating costs)
(541,910)
(3,473,575)
(5,096)
(4,020,581)
Operating costs
(232,489)
(297,771)
(100,966)
(631,226)
Equity in net earnings (loss) from investments
(1,385)
31,083
78,303
108,001
Noncash compensation expense and other
(1,865)
1,541
(184)
(508)
Segment adjusted EBITDA
$
431,545
$
1,199,801
$
332,194
$
1,963,540
Depreciation and amortization
$
(180,634)
$
(198,440)
$
(43,937)
$
(423,011)
Impairment charges (d)
$
(564,353)
$
(77,401)
$
—
$
(641,754)
Investments in unconsolidated affiliates
$
2,276
$
426,621
$
361,476
$
790,373
Total assets
$
6,437,301
$
13,449,529
$
2,082,846
$
21,969,676
Capital expenditures
$
362,811
$
1,504,881
$
40,478
$
1,908,170
(a) - Our Natural Gas Liquids segment has regulated and nonregulated operations. Our Natural Gas Liquids segment’s regulated operations had revenues of 1.5 billion, of which 1.3 billion related to revenues within the segment, and cost of sales and fuel of $375.0 million.
(b) - Our Natural Gas Pipelines segment has regulated and nonregulated operations. Our Natural Gas Pipelines segment’s regulated operations had revenues of $225.6 million and cost of sales and fuel of $22.4 million.
(c) - Intersegment revenues are primarily commodity sales, which are based on the contracted selling price that is generally index-based and settled monthly, and for the Natural Gas Gathering and Processing segment totaled $557.1 million. Intersegment revenues for the Natural Gas Liquids and Natural Gas Pipelines segments were not material.
(d) - Includes noncash impairment charges of $380.5 million related primarily to long-lived assets, $153.4 million related to goodwill and $30.5 million related to an investment in an unconsolidated affiliate in our Natural Gas Gathering and Processing segment; and $70.2 million related to long-lived assets and $7.2 million related to an investment in an unconsolidated affiliate in our Natural Gas Liquids segment.
Nine Months Ended September 30, 2020
Total Segments
Other and Eliminations
Total
(Thousands of dollars)
Reconciliations of total segments to consolidated
NGL and condensate sales
$
4,998,722
$
(513,170)
$
4,485,552
Residue natural gas sales
524,468
(10,860)
513,608
Gathering, processing and exchange services revenue
481,265
—
481,265
Transportation and storage revenue
484,598
(11,033)
473,565
Other
18,801
(1,126)
17,675
Total revenues (a)
$
6,507,854
$
(536,189)
$
5,971,665
Cost of sales and fuel (exclusive of depreciation and operating costs)
$
(4,020,581)
$
537,521
$
(3,483,060)
Operating costs
$
(631,226)
$
(5,207)
$
(636,433)
Depreciation and amortization
$
(423,011)
$
(3,003)
$
(426,014)
Impairment charges
$
(641,754)
$
—
$
(641,754)
Equity in net earnings from investments
$
108,001
$
—
$
108,001
Investments in unconsolidated affiliates
$
790,373
$
—
$
790,373
Total assets
$
21,969,676
$
811,200
$
22,780,876
Capital expenditures
$
1,908,170
$
15,833
$
1,924,003
(a) - Noncustomer revenue for the nine months ended September 30, 2020, totaled $103.0 million related primarily to gains from derivatives on commodity contracts.
Reconciliation of net income to total segment adjusted EBITDA
Net income
$
392,018
$
312,316
$
1,120,333
$
304,780
Add:
Interest expense, net of capitalized interest
184,049
176,371
554,529
535,955
Depreciation and amortization
154,542
153,245
468,583
426,014
Income tax expense
121,899
106,555
354,100
94,300
Impairment charges
—
—
—
641,754
Noncash compensation expense
12,978
1,606
37,086
1,261
Other corporate costs and equity AFUDC (a)
(944)
(5,865)
683
(40,524)
Total segment adjusted EBITDA
$
864,542
$
744,228
$
2,535,314
$
1,963,540
(a) - The three and nine months ended September 30, 2020, include corporate gains of $2.2 million and $22.2 million, respectively, on extinguishment of debt related to open market repurchases.
ITEM 2.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our unaudited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Quarterly Report, as well as our Annual Report.
RECENT DEVELOPMENTS
Please refer to the “Financial Results and Operating Information” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Quarterly Report for additional information.
Market Conditions, COVID-19 and Business Update - We experienced earnings growth from increased volumes in the third quarter 2021, compared with the third quarter 2020, due primarily to increased producer activity and rising gas-to-oil ratios in the Rocky Mountain region, increased ethane production across our system and higher commodity prices, highlighting both the resiliency of our integrated assets and the economic recovery from the pandemic. Although the energy industry has experienced many up and down cycles, we have positioned ourselves to reduce exposure to direct commodity price volatility. Each of our three reportable segments are primarily fee-based, and we expect our consolidated earnings to be approximately 90% fee-based in 2021. While our Natural Gas Gathering and Processing segment’s earnings are primarily fee-based, we have direct commodity price exposure related primarily to fee with POP contracts. In addition, our Natural Gas Gathering and Processing and Natural Gas Liquids segments are exposed to volumetric risk as a result of drilling and completion activity, normal volumetric well decline, severe weather disruption, operational outages and crude oil, NGL and natural gas demand. Our Natural Gas Pipelines segment is not exposed to significant volumetric risk due to nearly all of our capacity being subscribed under long-term firm fee-based contracts.
In continued response to COVID-19, we remain committed to managing the impact of the pandemic on our employees. We continue to protect our workforce and, as always, we remain focused on operating our assets safely, reliably and in an environmentally responsible manner. We continue to monitor the COVID-19 pandemic and have previously implemented our business continuity plans. ONEOK is a critical infrastructure business as defined by the United States Department of Homeland Security and, therefore, our workforce has remained fully engaged within federal, state and local government issued guidelines and safety-related ordinances. We continue to practice remote work procedures when possible to protect the safety of our employees and their families and continue to take precautions for our employees who work in the field or need to report to a ONEOK facility. We anticipate implementing a return to office plan in early 2022. We continue to apply risk-management and cybersecurity measures designed so that our systems remain functional in order to both serve our operational needs and to provide service to our customers.
Due to higher commodity prices, increased producer activity in the regions we operate and increased ethane production across our system, volumes in the third quarter 2021 increased, compared with the second quarter 2021, in both our Natural Gas Gathering and Processing and Natural Gas Liquids segments. We expect volumes to remain strong for the remainder of 2021 and into 2022 due to continued increases in producer activity, rising gas-to-oil ratios in the Rocky Mountain region and increased ethane demand from the petrochemical industry.
In February 2021, Winter Storm Uri brought significant challenges to the energy industry and our operating areas. Our employees were proactive in preparing for the severe winter weather, made the necessary operational adjustments to keep our assets operational and provided exceptional service to meet the needs of our customers during the difficult weather conditions as demand for natural gas, propane and electricity soared. This increased demand, coupled with supply reductions from producer wellhead freeze-offs and power outages impacting processing plants in the Mid-Continent and Rocky Mountain regions and the Permian Basin and fractionators in the Mid-Continent region, resulted in record high commodity prices at certain market hubs, particularly in the Mid-Continent region and in Texas. Commodity prices quickly returned to previous levels as the weather improved and natural gas supply returned.
Winter Storm Uri impacted all three of our operating segments, resulting in a net positive impact to our financial results, primarily in the first quarter 2021, as our ability to meet increased demand for natural gas and to provide services during the period offset the unfavorable volume impacts. Our well-positioned natural gas storage assets and market connected pipelines in our Natural Gas Pipelines segment were able to meet critical needs during this period of severe winter weather. The reliability of our interstate and intrastate assets enabled us to continue to provide our customers access to transportation services, park-and-loan services and additional natural gas supply if available, which improved our financial results. However, producer wellhead freeze-offs reduced February volumes in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, which negatively impacted our financial results in the first quarter 2021.
See Part I, Item 3, Quantitative and Qualitative Disclosures About Market Risk, in this Quarterly Report for more information on our exposure to market risk.
Sustainability and Social Responsibility - We continue to look for ways to reduce our environmental impact and utilize more efficient technologies. In 2021, we qualified for inclusion in the S&P Global Sustainability Yearbook and received Industry Mover status, which is awarded to a company that recorded the strongest year-over-year improvement in its industry. In addition, we received a perfect score of 100 in the Human Rights Campaign 2021 Corporate Equality Index. We have a stand-alone environmental sustainability team, formed in 2017, that accelerated our ongoing environmental stewardship efforts and is exploring ways to lower our greenhouse gas emissions. Additionally, in 2020, we created a group dedicated to the commercial development of renewable energy and low-carbon projects. Together with our sustainability team, we are actively researching opportunities that will complement our extensive midstream assets and expertise, strengthening the vital role we expect to play in the transformation to a lower-carbon economy.
In September 2021, we announced a 30% absolute greenhouse gas emissions reduction target, or 2.2 million metric tons, of our combined Scope 1 and Scope 2 emissions by 2030, compared with 2019 base-year levels. Scope 1 and 2 emissions represent our total operational emissions, including direct emissions from sources we operate and indirect emissions from the generation of purchased power. We anticipate several potential pathways toward achieving our emissions reduction target, which could include the electrification of certain natural gas compression assets across our operations, methane mitigation through best management practices and system optimizations. Additionally, we are identifying potential opportunities to collaborate with utilities and power generators to accelerate the availability of lower-carbon power options across our operations. We will maintain a disciplined capital approach and continue to discuss our total capital expenditures and provide our expected total capital spend annually in the “Liquidity and Capital Resources” section. We also expect to provide periodic updates regarding our progress towards our emissions reduction target at least annually.
Natural Gas - In our Natural Gas Gathering and Processing segment, gathered and processed volumes in the Rocky Mountain region increased in the third quarter 2021, compared with the second quarter 2021, due primarily to increased production. Volumes in the Rocky Mountain region also increased, compared with the third quarter 2020, due primarily to increased producer activity, rising gas-to-oil ratios and the impact of curtailed production in 2020. We expect to benefit from increased producer activity in the Rocky Mountain region, which includes the completion of previously drilled but uncompleted wells, and from our Bear Creek plant expansion that is complete and in-service. Our Bear Creek plant expansion increased our total processing capacity to approximately 1.7 Bcf/d in the Williston Basin.
In our Natural Gas Pipelines segment, our assets are connected to key supply areas and demand centers, including export markets in Mexico via Roadrunner and supply areas in Canada and the United States via our interstate and intrastate natural gas pipelines and Northern Border Pipeline, which enable us to provide essential natural gas transportation and storage services. Continued demand from local distribution companies, electric-generation facilities and large industrial companies resulted in low-cost expansions in 2019, 2020, 2021 and expansions expected to be completed in 2022 that position us well to provide additional services to our customers when needed. The contracted portion of our natural gas transportation capacity is not significantly impacted by commodity prices, as our end users rely on natural gas to support their business regardless of commodity price fluctuations. We continue to experience stable fee-based earnings with transportation capacity approximately
95% contracted with firm commitments, which we expect to continue for the remainder of 2021 at similarly contracted levels. Our ability to provide reliable service throughout the extreme weather conditions of Winter Storm Uri highlighted the importance of market-connected pipelines and storage assets and the value of these services. Since the storm, we have received increased interest from customers seeking additional long-term transportation and storage capacity on our system. As a result, we have recontracted storage services at higher rates and longer terms. Additionally, we are expanding the capacity of our storage facilities in Texas and exploring additional storage capacity expansion opportunities. In addition, during the first quarter 2021, we sold natural gas that we owned and held in storage, which benefited our segment’s financial results. During the extreme winter weather periods, we maximized natural gas storage withdrawals for firm service customers serving critical needs.
NGLs - In our Natural Gas Liquids segment, NGL volumes were higher in the third quarter 2021, compared with the second quarter 2021, due primarily to increased producer activity in the Rocky Mountain region and Permian Basin and increased ethane production across our system. Volumes were also higher, compared with the third quarter 2020, due primarily to increased producer activity in the Rocky Mountain region and Permian Basin, increased ethane production across our system in 2021 and the impact of curtailed production in 2020, offset partially by lower volumes in the Barnett Shale. We expect to benefit from increased producer activity and increased demand for ethane as the economic recovery continues and two new petrochemical plants are expected to come online in the next six to twelve months.
Ethane Production - Price differentials between ethane and natural gas can cause natural gas processors to extract ethane or leave it in the natural gas stream. As a result of these ethane economics, ethane volumes on our system can fluctuate period to period. Ethane volumes under long-term contracts delivered to our NGL system increased approximately 20 MBbl/d to an average of 455 MBbl/d in the third quarter 2021, compared with 435 MBbl/d in the second quarter 2021, due primarily to changes in ethane extraction economics. We estimate that there are more than 225 MBbl/d of discretionary ethane, consisting of more than 125 MBbl/d in the Rocky Mountain region and approximately 100 MBbl/d in the Mid-Continent region, that can be recovered and transported on our system. Ethane recovery opportunities will fluctuate based on regional natural gas pricing, ethane economics and potential incentivized recovery.
Growth Projects - We operate an integrated, reliable and diversified network of NGL and natural gas gathering, processing, fractionation, storage and transportation assets connecting supply in the Rocky Mountain, Mid-Continent and Permian regions with key market centers. We have completed significant capital-growth projects that include NGL pipelines, NGL fractionators, natural gas processing plants and related natural gas and NGL infrastructure. These projects provide us the capacity to benefit from future supply growth without significant capital investment. Our announced capital-growth projects are outlined in the table below:
Project
Scope
Approximate Costs (a)
Expected Completion
Natural Gas Gathering and Processing
(In millions)
Bear Creek plant expansion and related infrastructure
200 MMcf/d processing plant expansion and related gathering infrastructure in the Williston Basin
$405
Completed
Supported by acreage dedications with long-term primarily fee-based contracts
Natural Gas Liquids
Arbuckle II pipeline expansion
Increasing mainline capacity with additional pump facilities
$60
Completed
Increases capacity to 500 MBbl/d
MB-5 fractionator and related infrastructure
125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu
$750
Paused (b)
West Texas LPG pipeline expansion
Increasing mainline capacity by 40 MBbl/d
$145
Paused (b)
Mid-Continent fractionation facility expansions
65 MBbl/d of expansions at our Mid-Continent NGL facilities
$150
Paused (b)
(a) - Excludes capitalized interest/AFUDC.
(b) - We do not expect to complete construction by the original target completion date. While many of the construction activities on these projects were paused in 2020, some activity continued in order to complete the infrastructure necessary to support volumes until market conditions warrant full project completion.
Debt Repayments - On November 1, 2021, we redeemed the remaining $536.1 million of our $700 million, 4.25% senior notes due February 2022 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand and short-term borrowings. As of October 31, 2021, we had $150 million of short-term borrowings outstanding.
In June 2021, we repaid the remaining $11.7 million of Guardian Pipeline’s senior notes due December 2022 with cash on hand.
In the first quarter 2021, we repurchased in the open market outstanding principal of certain of our senior notes in the amount of $55.2 million for an aggregate repurchase price of $54.6 million with cash on hand.
Dividends - In February 2021, May 2021 and August 2021, we maintained and paid a quarterly dividend of $0.935 per share ($3.74 per share on an annualized basis), which is consistent with the respective quarters in the prior year. We declared a quarterly dividend of $0.935 per share ($3.74 per share on an annualized basis) in October 2021. The quarterly dividend will be paid November 15, 2021, to shareholders of record at the close of business on November 1, 2021.
Goodwill Impairment Review - We assess our goodwill for impairment at least annually as of July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. At July 1, 2021, we assessed qualitative factors to determine whether it was more likely than not that the fair value of each of our reporting units was less than their carrying amount. After assessing qualitative factors (including macroeconomic conditions, industry and market considerations, costs and overall financial performance), we determined that it was more likely than not that the fair value of each reporting unit was not less than their respective carrying value, that no further testing was necessary and that goodwill was not considered impaired.
FINANCIAL RESULTS AND OPERATING INFORMATION
How We Evaluate Our Operations
Management uses a variety of financial and operating metrics to analyze our performance. Our consolidated financial metrics include: (1) operating income; (2) net income; (3) diluted EPS; and (4) adjusted EBITDA. We evaluate segment operating results using adjusted EBITDA and our operating metrics, which include various volume and rate statistics that are relevant for the respective segment. These operating metrics allow investors to analyze the various components of segment financial results in terms of volumes and rate/price. Management uses these metrics to analyze historical segment financial results and as the key inputs for forecasting and budgeting segment financial results. For additional information on our operating metrics, see the respective segment subsections of this “Financial Results and Operating Information” section.
Non-GAAP Financial Measures - Adjusted EBITDA is a non-GAAP measure of our financial performance. Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, allowance for equity funds used during construction, noncash compensation expense and certain other noncash items. We believe this non-GAAP financial measure is useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial performance and is commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA should not be considered an alternative to net income, EPS or any other measure of financial performance presented in accordance with GAAP. Additionally, this calculation may not be comparable with similarly titled measures of other companies.
Selected Financial Results - The following table sets forth certain selected financial results for the periods indicated:
Three Months Ended
Nine Months Ended
Three Months
Nine Months
September 30,
September 30,
2021 vs. 2020
2021 vs. 2020
Financial Results
2021
2020
2021
2020
$ Increase (Decrease)
$ Increase (Decrease)
(Millions of dollars, except per share amounts)
Revenues
Commodity sales
$
4,204.8
$
1,852.2
$
10,115.7
$
5,004.4
2,352.6
5,111.3
Services
331.4
322.1
1,004.1
967.3
9.3
36.8
Total revenues
4,536.2
2,174.3
11,119.8
5,971.7
2,361.9
5,148.1
Cost of sales and fuel (exclusive of items shown separately below)
3,449.1
1,265.7
7,937.6
3,483.1
2,183.4
4,454.5
Operating costs
265.2
205.0
770.9
636.5
60.2
134.4
Depreciation and amortization
154.5
153.2
468.6
426.0
1.3
42.6
Impairment charges
—
—
—
604.0
—
(604.0)
Gain on sale of assets
(0.5)
—
(1.4)
(0.6)
0.5
0.8
Operating income
$
667.9
$
550.4
$
1,944.1
$
822.7
117.5
1,121.4
Equity in net earnings from investments
$
28.6
$
38.0
$
87.6
$
108.0
(9.4)
(20.4)
Impairment of equity investments
$
—
$
—
$
—
$
(37.7)
—
(37.7)
Interest expense, net of capitalized interest
$
(184.0)
$
(176.4)
$
(554.5)
$
(536.0)
7.6
18.5
Net income
$
392.0
$
312.3
$
1,120.3
$
304.8
79.7
815.5
Diluted EPS
$
0.88
$
0.70
$
2.50
$
0.71
0.18
1.79
Adjusted EBITDA
$
865.2
$
747.0
$
2,533.1
$
1,981.7
118.2
551.4
Capital expenditures
$
166.2
$
380.0
$
490.3
$
1,924.0
(213.8)
(1,433.7)
See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” section.
Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel in our Consolidated Statements of Income and, therefore, the impact is largely offset between these line items, except where noted.
Operating income increased $117.5 million for the three months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:
•Natural Gas Liquids - increases of $97.8 million in exchange services related primarily to higher volumes in the Rocky Mountain region and wider commodity price differentials and $10.3 million in optimization and marketing;
•Natural Gas Gathering and Processing - increases of $36.4 million from higher volumes due primarily to increased production in the Rocky Mountain region in 2021 and production curtailments in 2020 and $26.3 million due primarily to lower realized prices in 2020 impacting our fee with POP contracts; and
•Natural Gas Pipelines - an increase of $4.9 million in transportation and storage services due primarily to higher storage and firm transportation rates; offset by
•an increase of $60.2 million in consolidated operating costs due primarily to higher employee-related costs, materials and supplies, outside services and property taxes.
Operating income increased $1.1 billion for the nine months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:
•an increase of $604.0 million due to noncash impairment charges in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the nine months ended September 30, 2020;
•Natural Gas Liquids - increases of $299.0 million in exchange services related primarily to higher volumes in the Rocky Mountain region and $85.1 million in optimization and marketing, offset by a $46.2 million decrease from the impact of Winter Storm Uri in exchange services;
•Natural Gas Gathering and Processing - increases of $150.5 million due primarily to lower realized prices in 2020 impacting our fee with POP contracts and $94.2 million from higher volumes due primarily to increased production in the Rocky Mountain region in 2021 and production curtailments in 2020; and
•Natural Gas Pipelines - an increase of $106.8 million due primarily to increased natural gas sales; offset by
•an increase of $134.4 million in consolidated operating costs due primarily to higher employee-related costs, property taxes, materials and supplies, and the impact of a loss on the mark-to-market of our share-based deferred compensation plan in 2021 compared with a benefit in 2020; and
•an increase of $42.6 million in depreciation expense due to capital projects placed in service.
Net income and diluted EPS increased for the three months ended September 30, 2021, compared with the same period in 2020, due primarily to the items discussed above. These increases were offset partially by higher income taxes, lower equity in net earnings from investments and higher interest expense related to lower capitalized interest.
Net income and diluted EPS increased for the nine months ended September 30, 2021, compared with the same period in 2020, due primarily to the items discussed above and noncash impairment charges related to equity investments in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in the prior year. These increases were offset partially by higher income taxes, higher interest expense related to lower capitalized interest, lower equity AFUDC due to completed projects, lower equity in net earnings from investments and a $20.0 million gain in 2020 on extinguishment of debt related to open market repurchases.
Capital expenditures decreased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to our previously completed capital-growth projects, with the nine months ended September 30, 2021, also impacted by paused capital-growth projects.
Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.
Natural Gas Gathering and Processing
Overview -Our Natural Gas Gathering and Processing segment provides midstream services to producers in North Dakota, Montana, Wyoming, Kansas and Oklahoma. Raw natural gas is typically gathered at the wellhead, compressed and transported through pipelines to our processing facilities. Processed natural gas, usually referred to as residue natural gas, is then recompressed and delivered to natural gas pipelines, storage facilities and end users. The NGLs separated from the raw natural gas are sold and delivered through NGL pipelines to fractionation facilities for further processing.
Our Natural Gas Gathering and Processing segment’s earnings are primarily fee-based, but we have some direct commodity price exposure related primarily to fee with POP contracts. Under certain fee with POP contracts, our contractual fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. To mitigate the impact of this commodity price exposure, we have hedged a portion of our Natural Gas Gathering and Processing segment’s commodity price risk for the remainder of 2021 and into 2022. This segment has substantial long-term acreage dedications in some of the most productive areas of the Williston Basin, which helps to mitigate long-term volumetric risk.
Growth Projects - Our Natural Gas Gathering and Processing segment has invested in growth projects in NGL-rich areas in the Williston Basin. See “Growth Projects” in the “Recent Developments” section for discussion of our capital-growth project.
For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.
Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Gathering and Processing segment for the periods indicated:
Three Months Ended
Nine Months Ended
Three Months
Nine Months
September 30,
September 30,
2021 vs. 2020
2021 vs. 2020
Financial Results
2021
2020
2021
2020
$ Increase (Decrease)
$ Increase (Decrease)
(Millions of dollars)
NGL sales
$
788.8
$
216.3
$
1,782.3
$
488.7
572.5
1,293.6
Condensate sales
27.2
23.5
91.9
80.6
3.7
11.3
Residue natural gas sales
370.8
178.5
940.9
518.4
192.3
422.5
Gathering, compression, dehydration and processing fees and other revenue
41.7
41.1
116.6
121.5
0.6
(4.9)
Cost of sales and fuel (exclusive of depreciation and operating costs)
See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” section.
Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel and, therefore, the impact is largely offset between these line items.
Adjusted EBITDA increased $46.6 million for the three months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:
•an increaseof $36.4 million from higher volumes due primarily to increased production in the Rocky Mountain region in 2021 and production curtailments in 2020, offset partially by natural production declines in the Mid-Continent region;
•an increase of $26.3 million due primarily to lower realized prices in 2020 impacting our fee with POP contracts; and
•an increase of $7.3 million from a gain on the partial sale of an equity investment; offset by
•an increase of $23.9 million in operating costs due primarily to higher materials and supplies, employee-related costs and outside services due primarily to the growth of our operations.
Adjusted EBITDA increased $232.1 million for the nine months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:
•an increase of $150.5 million due primarily to lower realized prices in 2020 impacting our fee with POP contracts; and
•anincrease of $94.2 million from higher volumes due primarily to increased production in the Rocky Mountain region in 2021 and production curtailments in 2020, offset partially by natural production declines in the Mid-Continent region; offset by
•an increase of $24.2 million in operating costs due primarily to higher materials and supplies, employee-related costs and outside services due primarily to the growth of our operations.
The nine months ended September 30, 2020, includes $380.5 million of noncash impairment charges related primarily to certain long-lived asset groups in western Oklahoma, Kansas and the Powder River Basin that were not recoverable, a $153.4 million noncash impairment charge related to goodwill and a $30.5 million noncash impairment charge related to our 10.2% investment in Venice Energy Services Company.
Capital expenditures increased for the three months ended September 30, 2021, compared with the same period in 2020, due primarily to our Bear Creek plant expansion and decreased for the nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to our previously completed capital-growth projects.
(a) - Includes volumes for consolidated entities only.
(b) - Includes volumes we processed at company-owned and third-party facilities.
Our natural gas gathered and natural gas processed volumes increased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to increased producer activity and rising gas-to-oil ratios in the Rocky Mountain region and the impact of curtailed production in 2020, offset partially by natural production declines in the Mid-Continent region.
Our average fee rate increased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to an increase in the Rocky Mountain region’s contribution to our average fee rate.
Commodity Price Risk - See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 3, Quantitative and Qualitative Disclosures about Market Risk in this Quarterly Report.
Natural Gas Liquids
Overview - Our Natural Gas Liquids segment owns and operates facilities that gather, fractionate, treat and distribute NGLs and store NGL products, primarily in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region, which includes the Williston, Powder River and DJ Basins. We provide midstream services to producers of NGLs and deliver those products to the two primary market centers: one in the Mid-Continent in Conway, Kansas, and the other in the Gulf Coast in Mont Belvieu, Texas. We own or have an ownership interest in FERC-regulated NGL gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Kansas, Missouri, Nebraska, Iowa and Illinois. We have a 50% ownership interest in Overland Pass Pipeline Company, which operates an interstate NGL pipeline originating in Wyoming and Colorado and terminating in Kansas. The majority of the pipeline-connected natural gas processing plants in the Williston Basin, Oklahoma, Kansas and the Texas Panhandle are connected to our NGL gathering systems. We lease rail cars and own and operate truck- and rail-loading and -unloading facilities connected to our NGL fractionation, storage and pipeline assets. We also own FERC-regulated NGL distribution pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. A portion of our ONEOK North System transports refined petroleum products, including unleaded gasoline and diesel, from Kansas to Iowa.
Growth Projects - Our Natural Gas Liquids segment invests in projects to transport, fractionate, store and deliver to market centers NGL supply from shale and other resource development areas. Our growth strategy is focused around connecting diversified supply basins from the Rocky Mountain region through the Mid-Continent region and the Permian Basin with NGL product demand from the petrochemical and refining industries and NGL export demand in the Gulf Coast. See “Growth Projects” in the “Recent Developments” section for discussion of our capital-growth projects.
In the nine months ended September 30, 2021, we connected one third-party natural gas processing plant in the Permian Basin and one third-party natural gas processing plant in the Rocky Mountain region to our NGL system.
For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.
Selected Financial Results and Operating Information -The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids segment for the periods indicated:
Three Months Ended
Nine Months Ended
Three Months
Nine Months
September 30,
September 30,
2021 vs. 2020
2021 vs. 2020
Financial Results
2021
2020
2021
2020
$ Increase (Decrease)
$ Increase (Decrease)
(Millions of dollars)
NGL and condensate sales
$
3,853.1
$
1,658.1
$
9,097.5
$
4,429.4
2,195.0
4,668.1
Exchange service revenues and other
136.0
134.3
414.6
377.7
1.7
36.9
Transportation and storage revenues
40.5
39.8
127.1
131.4
0.7
(4.3)
Cost of sales and fuel (exclusive of depreciation and operating costs)
See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” section.
Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel and, therefore, the impact is largely offset between these line items.
Adjusted EBITDA increased $81.0 million for the three months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:
•an increase of $97.8 million in exchange services due primarily to $59.6 million in higher volumes primarily in the Rocky Mountain region and Permian Basin, offset partially by lower volumes in the Barnett Shale, and $29.5 million related to wider commodity price differentials; and
•an increase of $10.3 million in optimization and marketing due primarily to wider locations and commodity price differentials; offset by
•an increase of $25.4 million in operating costs due primarily to higher employee-related costs, increased property taxes associated with our completed capital-growth projects and higher outside services.
Adjusted EBITDA increased $248.3 million for the nine months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:
•an increase of $299.0 million in exchange services (excluding the impact of Winter Storm Uri discussed below) due primarily to:
◦$249.6 million in higher volumes in the Rocky Mountain region and lower transportation costs, offset by $11.3 million in lower volumes primarily in the Barnett Shale,
◦$65.9 million related to wider commodity price differentials, and
◦$12.9 million related to the recognition of proceeds previously considered a gain contingency, offset by
◦$15.6 million related to lower earnings on unfractionated NGLs held in inventory due primarily to decreasing inventory levels throughout 2020; and
•an increase of $85.1 million in optimization and marketing due primarily to wider location and commodity price differentials, increased activities during Winter Storm Uri and higher earnings on purity NGL sales; offset by
•the negative impact of Winter Storm Uri of $46.2 million in exchange services due primarily to decreased volumes across our operations and higher electricity costs;
•an increase of $68.9 million in operating costs due primarily to higher employee-related costs, increased property taxes associated with our completed capital-growth projects and higher outside services; and
•a decrease of $17.0 million from lower equity in net earnings from investments due primarily to lower volumes on Overland Pass Pipeline.
The nine months ended September 30, 2020, includes $70.2 million of noncash impairment charges related to certain inactive assets and a $7.2 million noncash impairment charge related to our 50% investment in Chisholm Pipeline Company.
Capital expenditures decreased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to previously completed capital-growth projects, with the nine months ended also impacted by paused capital-growth projects.
Three Months Ended
Nine Months Ended
September 30,
September 30,
Operating Information
2021
2020
2021
2020
Raw feed throughput (MBbl/d) (a)
1,275
1,162
1,174
1,088
Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon)
$
0.00
$
0.03
$
(0.01)
$
0.01
(a) - Represents physical raw feed volumes on which we charge a fee for transportation and/or fractionation services.
Volumes increased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to increased production primarily in the Rocky Mountain region and increased ethane production across our system.
Volumes for the nine months ended September 30, 2021, also increased due to the impact of curtailed production across our system in 2020 and were offset partially by the impact of Winter Storm Uri in 2021. Volumes for the three months ended September 30, 2021, have also benefited from increased production in the Permian Basin, offset partially by lower volumes in the Barnett Shale.
Natural Gas Pipelines
Overview - Our Natural Gas Pipelines segment, through its wholly owned assets primarily in Oklahoma, Texas and the upper Midwest, provides transportation and storage services to end users, such as natural gas distribution and electric-generation companies, that require natural gas to operate their businesses regardless of location price differentials. We have 50% ownership interests in Northern Border Pipeline and Roadrunner, which provide transportation services to various end users.
Selected Financial Resultsand Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Pipelines segment for the periods indicated:
Three Months Ended
Nine Months Ended
Three Months
Nine Months
September 30,
September 30,
2021 vs. 2020
2021 vs. 2020
Financial Results
2021
2020
2021
2020
$ Increase (Decrease)
$ Increase (Decrease)
(Millions of dollars)
Transportation revenues
$
101.2
$
96.4
$
313.0
$
303.1
4.8
9.9
Storage revenues
19.1
16.6
52.6
50.1
2.5
2.5
Residue natural gas sales and other revenues
0.2
4.3
116.1
6.9
(4.1)
109.2
Cost of sales and fuel (exclusive of depreciation and operating costs)
See reconciliation of net income to adjusted EBITDA in the “Non-GAAP Financial Measures” section.
Adjusted EBITDA decreased $7.1 million for the three months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:
•a decrease of $7.4 million from lower equity in net earnings from investments due primarily to decreased firm transportation revenues on Northern Border Pipeline; and
•an increase of $5.8 million in operating costs due primarily to higher employee-related costs and higher supplies expenses; offset by
•an increase of $4.9 million in transportation and storage services due primarily to higher storage and firm transportation rates.
Adjusted EBITDA increased $91.4 million for the nine months ended September 30, 2021, compared with the same period in 2020, primarily as a result of the following:
•an increase of $106.8 million due primarily to higher average natural gas prices on 5.2 Bcf of natural gas sales in the first quarter 2021 of volumes previously held in inventory, compared with 1.2 Bcf in the first quarter 2020; and
•an increase of $7.0 million in transportation services due primarily to higher park-and-loan revenue and higher interruptible transportation revenue in the first quarter 2021, offset partially by a favorable $13.5 million contract settlement in April 2020; offset by
•an increase of $16.4 million in operating costs due primarily to higher employee-related costs and higher supplies expenses; and
•a decrease of $7.4 million from lower equity in net earnings from investments due primarily to decreased firm transportation revenues on Northern Border Pipeline.
Capital expenditures increased for the three and nine months ended September 30, 2021, compared with the same periods in 2020, due primarily to capital-growth and maintenance capital projects.
Three Months Ended
Nine Months Ended
September 30,
September 30,
Operating Information (a)
2021
2020
2021
2020
Natural gas transportation capacity contracted (MDth/d)
7,335
7,349
7,353
7,485
Transportation capacity contracted
94
%
94
%
94
%
96
%
(a) - Includes volumes for consolidated entities only.
Roadrunner has contracted all of its westbound capacity through 2041.
Northern Border Pipeline has contracted substantially all of its long-haul transportation capacity through the fourth quarter 2021.
In February 2021, our subsidiary, Midwestern Gas Transmission Company, filed a proposed change in rates pursuant to Section 4 of the Natural Gas Act with the FERC. The FERC is currently reviewing the filing. While the ultimate outcome of the filing cannot be predicted, we do not expect the ultimate outcome to impact materially our results of operations.
The following table sets forth a reconciliation of net income, the nearest comparable GAAP financial performance measure, to adjusted EBITDA for the periods indicated:
Three Months Ended
Nine Months Ended
September 30,
September 30,
2021
2020
2021
2020
Reconciliation of net income to adjusted EBITDA
(Thousands of dollars)
Net income
$
392,018
$
312,316
$
1,120,333
$
304,780
Add:
Interest expense, net of capitalized interest
184,049
176,371
554,529
535,955
Depreciation and amortization
154,542
153,245
468,583
426,014
Income tax expense
121,899
106,555
354,100
94,300
Impairment charges
—
—
—
641,754
Noncash compensation expense (a)
12,978
1,606
37,086
1,261
Equity AFUDC and other noncash items
(246)
(3,084)
(1,485)
(22,346)
Adjusted EBITDA (b)
865,240
747,009
2,533,146
1,981,718
Reconciliation of segment adjusted EBITDA to adjusted EBITDA
Segment adjusted EBITDA:
Natural Gas Gathering and Processing
$
229,657
$
183,148
$
663,639
$
431,545
Natural Gas Liquids
532,159
451,243
1,448,078
1,199,801
Natural Gas Pipelines
102,726
109,837
423,597
332,194
Other (b)
698
2,781
(2,168)
18,178
Adjusted EBITDA
$
865,240
$
747,009
$
2,533,146
$
1,981,718
(a) - Includes a loss of $6.9 million and a benefit of $16.9 million for the nine months ended September 30, 2021 and 2020, respectively, related to the mark-to-market of our share-based deferred compensation plan.
(b) - The three and nine months ended September 30, 2020, includes corporate gains of $2.2 million and $22.2 million, respectively, on extinguishment of debt related to open market repurchases.
CONTINGENCIES
See Note J of the Notes to Consolidated Financial Statements in this Quarterly Report for discussion of our legal proceedings.
LIQUIDITY AND CAPITAL RESOURCES
General -Our primary sources of cash inflows are operating cash flows, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement, debt issuances and the issuance of common stock for our liquidity and capital resources requirements. In addition, we expect cash outflows for the remainder of 2021 to be primarily related to dividends paid to shareholders and capital expenditures.
We expect our sources of cash inflows to provide sufficient resources to finance our operations, capital expenditures and quarterly cash dividends. We believe we have sufficient liquidity due to our $2.5 Billion Credit Agreement, which expires in June 2024 and access to $1.0 billion available through our “at-the-market” equity program. As of the date of this report, no shares have been sold through our “at-the-market” equity program.
We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. For additional information on our interest-rate swaps, see Note C of the Notes to Consolidated Financial Statements in this Quarterly Report.
Guarantees and Cash Management - We and ONEOK Partners are issuers of certain public debt securities. We guarantee certain indebtedness of ONEOK Partners, and ONEOK Partners and the Intermediate Partnership guarantee certain of our indebtedness. The guarantees in place for our and ONEOK Partners’ indebtedness are full, irrevocable, unconditional and absolute joint and several guarantees to the holders of each series of outstanding securities. Liabilities under the guarantees rank equally in right of payment with all existing and future senior unsecured indebtedness. As ONEOK Partners and the Intermediate Partnership are consolidated subsidiaries of ONEOK, separate financial statements for the guarantors are not required as long as the alternative disclosure required by Rule 13-01 is provided, which includes narrative disclosure and summarized financial information. The Intermediate Partnership holds all of ONEOK Partners’ interests and equity in its subsidiaries, which are non-guarantors, and substantially all the assets and operations reside with non-guarantor operating
subsidiaries. Therefore, as allowed under Rule 13-01, we have excluded the summarized financial information for each issuer and guarantor as the combined financial information of the subsidiary issuer and parent guarantor, excluding our ownership of all the interests in ONEOK Partners, reflect no material assets, liabilities or results of operations, apart from the guaranteed indebtedness. For additional information on our and ONEOK Partners’ indebtedness, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.
We use a centralized cash management program that concentrates the cash assets of our non-guarantor operating subsidiaries in joint accounts for the purposes of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Our centralized cash management program provides that funds in excess of the daily needs of our operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within our consolidated group. Our operating subsidiaries participate in this program to the extent they are permitted pursuant to FERC regulations or their operating agreements. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash to us.
Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, distributions received from our equity-method investments, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement. As of September 30, 2021, we are in compliance with all covenants of the $2.5 Billion Credit Agreement.
At September 30, 2021, we had no borrowings under our $2.5 Billion Credit Agreement and $224.3 million of cash and cash equivalents.
As of September 30, 2021, we had a working capital deficit of $136.0 million (defined as current assets less current liabilities). Although working capital is influenced by several factors, including, among other things: (i) the timing of (a) debt and equity issuances, (b) the funding of capital expenditures, (c) scheduled debt payments, and (d) accounts receivable and payable; and (ii) the volume and cost of inventory and commodity imbalances, our working capital deficit at September 30, 2021, was driven primarily by current maturities of long-term debt. We may have working capital deficits in future periods as we continue to repay long-term debt. We do not expect this working capital deficit to have an adverse impact to our cash flows or operations.
For additional information on our $2.5 Billion Credit Agreement, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.
Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term financing requirements by issuing long-term notes, as needed. Other options to obtain financing include, but are not limited to, issuing common stock, loans from financial institutions, issuance of convertible debt securities or preferred equity securities, asset securitization and the sale and lease-back of facilities.
Debt Repayments -On November 1, 2021, we redeemed the remaining $536.1 million of our $700 million, 4.25% senior notes due February 2022 at 100% of the principal amount, plus accrued and unpaid interest, with cash on hand and short-term borrowings. As of October 31, 2021, we had $150 million of short-term borrowings outstanding.
In June 2021, we repaid the remaining $11.7 million of Guardian Pipeline’s senior notes due December 2022 with cash on hand.
In the first quarter 2021, we repurchased in the open market outstanding principal of certain of our senior notes in the amount of $55.2 million for an aggregate repurchase price of $54.6 million with cash on hand.
For additional information on our long-term debt, see Note D of the Notes to Consolidated Financial Statements in this Quarterly Report.
Capital Expenditures- We classify expenditures that are expected to generate additional revenue, return on investment or significant operating efficiencies as capital-growth expenditures. Maintenance capital expenditures are those capital expenditures required to maintain our existing assets and operations and do not generate additional revenues. Maintenance capital expenditures are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives. Our capital expenditures are financed typically through operating cash flows and short- and long-term debt.
Capital expenditures, excluding AFUDC and capitalized interest, were $490.3 million and $1.9 billion for the nine months ended September 30, 2021 and 2020, respectively.
We expect total capital expenditures, excluding AFUDC and capitalized interest, of $525-$675 million in 2021.
Credit Ratings - Our long-term debt credit ratings as of October 25, 2021, are shown in the table below:
Rating Agency
Long-Term Rating
Short-Term Rating
Outlook
Moody’s
Baa3
Prime-3
Stable
S&P
BBB
A-2
Stable
Fitch
BBB
F2
Stable
Our credit ratings, which are investment grade, may be affected by a material change in our financial ratios or a material event affecting our business and industry. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, our cost to borrow funds under our $2.5 Billion Credit Agreement could increase and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our $2.5 Billion Credit Agreement, which expires in 2024. An adverse credit rating change alone is not a default under our $2.5 Billion Credit Agreement.
In the normal course of business, our counterparties provide us with secured and unsecured credit. In the event of a downgrade in our credit ratings or a significant change in our counterparties’ evaluation of our creditworthiness, we could be required to provide additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to conduct business with such counterparties. We may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments.
Dividends -Holders of our common stock share equally in any common stock dividends declared by our Board of Directors, subject to the rights of the holders of outstanding preferred stock. In February 2021, May 2021 and August 2021 we paid a dividend of $0.935 per share ($3.74 per share on an annualized basis). A dividend of $0.935 per share was declared for the shareholders of record at the close of business on November 1, 2021, payable November 15, 2021.
Our Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5% per year. We paid dividends for the Series E Preferred Stock of $0.3 million in February 2021, May 2021 and August 2021. Dividends totaling $0.3 million were declared for the Series E Preferred Stock and are payable November 15, 2021.
For the nine months ended September 30, 2021, our cash flows from operations exceeded dividends paid by $241.0 million. We expect our cash flows from operations to continue to sufficiently fund our cash dividends. To the extent operating cash flows are not sufficient to fund our dividends, we may utilize cash on hand from other sources of short- and long-term liquidity to fund a portion of our dividends.
CASH FLOW ANALYSIS
We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that affect net income but do not result in actual cash receipts or payments during the period and for operating cash items that do not impact net income. These reconciling items can include depreciation and amortization, impairment charges, allowance for equity funds used during construction, gain or loss on sale of assets, deferred income taxes, net undistributed earnings from equity-method investments, share-based compensation expense, other amounts and changes in our assets and liabilities not classified as investing or financing activities.
The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:
Variances
Nine Months Ended
2021 vs. 2020
September 30,
Favorable (Unfavorable)
2021
2020
(Millions of dollars)
Total cash provided by (used in):
Operating activities
$
1,491.1
$
1,103.1
$
388.0
Investing activities
(475.4)
(1,981.9)
1,506.5
Financing activities
(1,315.9)
1,304.9
(2,620.8)
Change in cash and cash equivalents
(300.2)
426.1
(726.3)
Cash and cash equivalents at beginning of period
524.5
21.0
503.5
Cash and cash equivalents at end of period
$
224.3
$
447.1
$
(222.8)
Operating Cash Flows - Operating cash flows are affected by earnings from our business activities and changes in our operating assets and liabilities. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows. Our operating cash flows can also be impacted by changes in our NGLs and natural gas inventory balances, which are driven primarily by commodity prices, supply, demand and the operation of our assets.
Cash flows from operating activities, before changes in operating assets and liabilities for the nine months ended September 30, 2021, increased $542.3 million compared with the same period in 2020. This increase is due primarily to higher net income resulting from higher exchange services in our Natural Gas Liquids segment, higher realized prices and increased volumes in our Natural Gas Gathering and Processing segment and natural gas sales in our Natural Gas Pipelines segment, as discussed in “Financial Results and Operating Information.”
The changes in operating assets and liabilities decreased operating cash flows $500.8 million for the nine months ended September 30, 2021, compared with a decrease of $346.6 million for the same period in 2020. This change is due primarily to changes in accounts receivable resulting from the timing of receipt of cash from customers and NGLs and natural gas in storage, both of which vary from period to period and with changes in commodity prices; offset partially by changes in accounts payable resulting from the timing of payments to vendors, suppliers and other third parties; and changes in other assets and liabilities.
Investing Cash Flows - Cash used in investing activities for the nine months ended September 30, 2021, decreased $1.5 billion, compared with the same period in 2020, due primarily to reduced capital expenditures related to our completed and paused capital-growth projects.
Financing Cash Flows - Cash from financing activities for the nine months ended September 30, 2021, decreased $2.6 billion, compared with the same period in 2020, due primarily to the issuances of $3.25 billion in long-term debt and the issuance of common stock in 2020, offset partially by the repayment of long-term debt in 2020.
REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS
Environmental Matters -We are subject to a variety of historical preservation and environmental laws and/or regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous wastes, wetlands and waterways preservation, wildlife conservation, cultural resources protection, hazardous materials transportation, and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties, costs, liabilities (including joint and several liability for the obligations of others), reputational harm and/or interruptions in our operations that could be material to our results of operations or financial condition. In addition, emissions controls and/or other regulatory or permitting mandates under the Clean Air Act and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. We also
cannot assure that existing permits will not be revised or cancelled, potentially impacting facility construction activities or ongoing operations.
Pipeline Security - The United States Department of Homeland Security’s Transportation Security Administration (TSA) issued two Security Directives in 2021 in response to ongoing cybersecurity threats to the pipeline industry. The first Security Directive was issued in May 2021 and requires critical pipeline owners and operators to (1) report confirmed and potential cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency (CISA); (2) designate a cybersecurity coordinator to be available 24 hours a day, seven days a week; (3) review current practices; and, (4) identify any gaps and related remediation measures to address cyber-related risks and report the results to TSA and CISA within 30 days. The second Security Directive was issued in July 2021 and requires owners and operators of TSA-designated critical pipelines to implement specific mitigation measures to protect against ransomware and other known threats to information technology and operational technology systems, develop and implement a cybersecurity contingency and recovery plan, and conduct a cybersecurity architecture design review. While compliance with the Security Directives is utilizing significant internal resources, we do not expect it to have a material impact on our results of operations, financial position or cash flows.
Additional information about our regulatory, environmental and safety matters can be found in “Regulatory, Environmental and Safety Matters” under Part I, Item 1, Business, in our Annual Report.
IMPACT OF NEW ACCOUNTING STANDARDS
See Note A of the Notes to Consolidated Financial Statements in this Quarterly Report for discussion of new accounting standards.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of our Consolidated Financial Statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.
Information about our critical accounting policies and estimates is included under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Critical Accounting Policies and Estimates,” in our Annual Report.
FORWARD-LOOKING STATEMENTS
Some of the statements contained and incorporated in this Quarterly Report are forward-looking statements as defined under federal securities laws. The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flows and projected levels of dividends), liquidity, management’s plans and objectives for our future capital-growth projects and other future operations (including plans to construct additional natural gas and NGL pipelines, processing and fractionation facilities and related cost estimates), our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under federal securities legislation and other applicable laws. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.
Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Quarterly Report identified by words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “target,” “guidance,” “intend,” “may,” “might,” “outlook,” “plan,” “potential,” “project,” “scheduled,” “should,” “will,” “would,” and other words and terms of similar meaning.
One should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
•the length, severity and reemergence of a pandemic or other health crisis, such as the COVID-19 pandemic and the measures that international, federal, state and local governments, agencies, law enforcement and/or health authorities implement to address it, which may (as with COVID-19) precipitate or exacerbate one or more of the factors herein, reduce the demand for natural gas, NGLs and crude oil and significantly disrupt or prevent us and our customers and counterparties from operating in the ordinary course for an extended period and increase the cost of operating our business;
•operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruption;
•the impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers’ desire and ability to drill and obtain necessary permits; regulatory compliance; reserve performance; and capacity constraints and/or shut downs on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;
•risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling, the shutting-in of production by producers, actions taken by federal, state or local governments to require producers to prorate or to cut their production levels as a way to address any excess market supply situations or extended periods of ethane rejection;
•demand for our services and products in the proximity of our facilities;
•economic climate and growth in the geographic areas in which we operate;
•the risk of a slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;
•performance of contractual obligations by our customers, service providers, contractors and shippers;
•the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, cybersecurity, climate change initiatives, emissions credits, carbon offsets, carbon pricing, production limits and authorized rates of recovery of natural gas and natural gas transportation costs;
•changes in demand for the use of natural gas, NGLs and crude oil because of the development of new technologies or other market conditions caused by concerns about climate change;
•the transition to a lower-carbon economy, including the timing and extent of the transition, as well as the expected role of different energy sources in such a transition;
•the pace of technological advancements and industry innovation, including those focused on reducing greenhouse gas emissions and advancing other climate-related initiatives, and our ability to take advantage of those innovations and developments;
•the effectiveness of our risk management strategies, including mitigating climate-related risks;
•our ability to identify and execute opportunities, and the economic viability of those opportunities, including those relating to renewable natural gas, carbon capture, use and storage, other renewable energy sources such as solar and wind and alternative low carbon fuel sources such as hydrogen;
•the ability of our existing assets and our ability to apply and continue to develop our expertise to support the growth of, and transition to, various renewable and alternative energy opportunities, including through the positioning and optimization of our assets;
•our ability to efficiently reduce the carbon intensity of our operations (both Scope 1 and 2 emissions), including through the use of lower carbon power alternatives, management practices and system optimizations;
•the necessity to direct our focus on maintaining and enhancing our existing assets instead of efforts to reduce our greenhouse gas emissions;
•the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;
•acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’, customers’ or shippers’ facilities;
•the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions throughout the world;
•the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;
•the timing and extent of changes in energy commodity prices, including changes due to production decisions by other countries, such as the failure of countries to abide by agreements to reduce production volumes;
•competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel;
•the ability to market pipeline capacity on favorable terms, including the effects of:
– future demand for and prices of natural gas, NGLs and crude oil;
– competitive conditions in the overall energy market;
– availability of supplies of United States natural gas and crude oil; and
– availability of additional storage capacity;
•the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;
•the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;
•risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;
•our ability to control operating costs and make cost-saving changes;
•the risk inherent in the use of information systems in our respective businesses and those of our counterparties and service providers, including cyber-attacks, which, according to experts, have increased in volume and sophistication since the beginning of the COVID-19 pandemic; implementation of new software and hardware; and the impact on the timeliness of information for financial reporting;
•the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;
•the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates;
•the results of governmental actions, administrative proceedings and litigation, regulatory actions, executive orders, rule changes and receipt of expected clearances involving any local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the Department of Homeland Security, the PHMSA, the EPA and the CFTC;
•the mechanical integrity of facilities and pipelines operated;
•the capital-intensive nature of our businesses;
•the impact of unforeseen changes in interest rates, debt and equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and postretirement expense and funding resulting from changes in equity and bond market returns;
•actions by rating agencies concerning our credit;
•our indebtedness and guarantee obligations could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt or have other adverse consequences;
•our ability to access capital at competitive rates or on terms acceptable to us;
•our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems;
•our ability to control construction costs and completion schedules of our pipelines and other projects;
•difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or pipelines;
•the uncertainty of estimates, including accruals and costs of environmental remediation;
•the impact of uncontracted capacity in our assets being greater or less than expected;
•the impact of potential impairment charges;
•the profitability of assets or businesses acquired or constructed by us;
•risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions;
•the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant;
•the impact and outcome of pending and future litigation;
•the impact of recently issued and future accounting updates and other changes in accounting policies; and
•the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also affect adversely our future results. These and
other risks are described in greater detail in Part I, Item 1A, Risk Factors, in our Annual Report and in our other filings that we make with the SEC, which are available via the SEC’s website at www.sec.gov and our website at www.oneok.com. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Any such forward-looking statement speaks only as of the date on which such statement is made, and other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.
ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our exposure to market risk discussed below includes forward-looking statements and represents an estimate of possible changes in future earnings that could occur assuming hypothetical future movements in interest rates or commodity prices. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur since actual gains and losses will differ from those estimated based on actual fluctuations in interest rates or commodity prices and the timing of transactions.
We are exposed to market risk due to commodity price and interest-rate volatility. Market risk is the risk of loss arising from adverse changes in market rates and prices. We may use financial instruments, including forward sales, swaps, options and futures, to manage the risks of certain identifiable or anticipated transactions and achieve more predictable cash flows. Our risk-management function follows policies and procedures established by our Risk Oversight and Strategy Committee to monitor our natural gas, condensate and NGL marketing activities and interest rates to ensure our hedging activities mitigate market risks and comply with approved thresholds or limits. We do not use financial instruments for trading purposes.
We utilize a sensitivity analysis model to assess the risk associated with our derivative portfolio. The sensitivity analysis measures the potential change in fair value of our derivative instruments based upon a hypothetical 10% movement in the underlying commodity prices or interest rates. In addition to these variables, the fair value of our derivative portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. Because we enter into these derivative instruments for the purpose of mitigating the risks that accompany certain of our business activities, as described below, the change in the market value of our derivative portfolio would typically be offset largely by a corresponding gain or loss on the hedged item.
COMMODITY PRICE RISK
As part of our hedging strategy, we use commodity derivative financial instruments and physical-forward contracts described in Note C of the Notes to Consolidated Financial Statements in this Quarterly Report to reduce the impact of near-term price fluctuations of natural gas, NGLs and condensate.
Although our businesses are primarily fee-based, in our Natural Gas Gathering and Processing segment, we are exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our fee with POP contracts. Under certain fee with POP contracts, our contractual fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. In certain commodity price environments, our contractual fees on these fee with POP contracts may decrease, which would impact the average fee rate in our Natural Gas Gathering and Processing segment. We are exposed to basis risk between the various production and market locations where we buy and sell commodities.
The following table presents the effect a hypothetical 10% change in the underlying commodity prices would have on the estimated fair value of our commodity derivative instruments for the periods indicated:
Commodity Contracts
September 30, 2021
December 31, 2020
(Millions of dollars)
Crude oil and NGLs
$
50.4
$
20.0
Natural gas
19.5
10.6
Total change in estimated fair value of commodity contracts
$
69.9
$
30.6
Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on our commodity derivative contracts assuming hypothetical movements in future market prices and is not necessarily indicative of actual results that may occur. Actual gains and losses may differ from estimates due to actual fluctuations in market prices, as well as changes in our commodity derivative portfolio during the year.
The following tables set forth hedging information as of October 31, 2021, for our Natural Gas Gathering and Processing segment’s forecasted equity volumes for the periods indicated:
Our Natural Gas Gathering and Processing segment’s commodity price sensitivity is estimated as a hypothetical change in the price of NGLs, crude oil and natural gas at September 30, 2021. Condensate sales are typically based on the price of crude oil. Assuming normal operating conditions, we estimate the following for our forecasted equity volumes:
•a $0.01 per-gallon change in the composite price of NGLs, excluding ethane, would change adjusted EBITDA for the three months ending December 31, 2021, and for the year ending December 31, 2022, by approximately $0.7 million and $2.6 million, respectively;
•a $1.00 per-barrel change in the price of crude oil would change adjusted EBITDA for the three months ending December 31, 2021, and for the year ending December 31, 2022, by approximately $0.2 million and $0.8 million, respectively; and
•a $0.10 per-MMBtu change in the price of residue natural gas would change adjusted EBITDA for the three months ending December 31, 2021, and for the year ending December 31, 2022, by approximately $1.5 million and $5.3 million, respectively.
These estimates do not include any effects of hedging or effects on demand for our services or natural gas processing plant operations that might be caused by, or arise in conjunction with, commodity price fluctuations. For example, a change in the gross processing spread may cause a change in the amount of ethane extracted from the natural gas stream, impacting gathering and processing financial results for certain contracts.
INTEREST-RATE RISK
We are exposed to interest-rate risk through borrowings under our $2.5 Billion Credit Agreement, commercial paper program and long-term debt issuances. Future increases in commercial paper rates or bond rates could expose us to increased interest costs on future borrowings. We may manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. Interest-rate swaps are agreements to exchange interest payments at some future point based on specified notional amounts.
At September 30, 2021, and December 31, 2020, we had forward-starting interest-rate swaps with notional amounts totaling $1.1 billion to hedge the variability of interest payments on a portion of our forecasted debt issuances. All of our interest-rate swaps are designated as cash flow hedges.
The following table presents the effect of a 10% hypothetical change in interest rates on the estimated fair value of our interest- rate derivative instruments for the periods indicated:
September 30, 2021
December 31, 2020
(Millions of dollars)
Forward-starting interest-rate swaps
$
18.5
$
12.9
Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on our interest-rate derivative contracts assuming hypothetical movements in future interest rates and is not necessarily indicative of
actual results that may occur. Actual gains and losses may differ from estimates due to actual fluctuations in interest rates, as well as changes in our interest-rate derivative portfolio during the year.
See Note C of the Notes to Consolidated Financial Statements in this Quarterly Report for more information on our hedging activities.
COUNTERPARTY CREDIT RISK
We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. Certain of our counterparties may be impacted by a relatively low commodity price environment and could experience financial problems, which could result in nonpayment and/or nonperformance, which could impact adversely our results of operations.
The creditworthiness of our counterparties, which are primarily investment grade, is consistent with that discussed in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in our Annual Report.
ITEM 1A.RISK FACTORS
Our investors should consider the risks set forth in Part I, Item 1A, Risk Factors, of our Annual Report that could affect us and our business. Although we have tried to discuss key factors, our investors need to be aware that other risks may prove to be important in the future. New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance. Investors should consider carefully the discussion of risks and the other information included or incorporated by reference in this Quarterly Report, including “Forward-Looking Statements,” which are included in Part I, Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 4.CONTROLS AND PROCEDURES
Quarterly Evaluation of Disclosure Controls and Procedures - Our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this report based on the evaluation of the controls and procedures required by Rules 13a-15(b) and 15d-15(b) of the Exchange Act.
Changes in Internal Control Over Financial Reporting -There have been no changes in our internal control over financial reporting during the quarter ended September 30, 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
Additional information about our legal proceedings is included in Note J of the Notes to Consolidated Financial Statements in this Quarterly Report and under Note N of the Notes to Consolidated Financial Statements in our Annual Report.
ITEM 2.UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Readers of this report should not rely on or assume the accuracy of any representation or warranty or the validity of any opinion contained in any agreement filed as an exhibit to this Quarterly Report, because such representation, warranty or opinion may be subject to exceptions and qualifications contained in separate disclosure schedules, may represent an allocation of risk between parties in the particular transaction, may be qualified by materiality standards that differ from what may be viewed as material for securities law purposes, or may no longer continue to be true as of any given date. All exhibits attached to this Quarterly Report are included for the purpose of complying with requirements of the SEC. Other than the certifications made by our officers pursuant to the Sarbanes-Oxley Act of 2002 included as exhibits to this Quarterly Report, all exhibits are included only to provide information to investors regarding their respective terms and should not be relied upon as constituting or providing any factual disclosures about us, any other persons, any state of affairs or other matters.
The following exhibits are filed as part of this Quarterly Report:
Inline 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.
Cover Page Interactive Data File (embedded within the Inline XBRL document and contained in Exhibit 101).
Attached as Exhibit 101 to this Quarterly Report are the following Inline XBRL-related documents: (i) Document and Entity Information; (ii) Consolidated Statements of Income for the three and nine months ended September 30, 2021 and 2020; (iii) Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2021 and 2020; (iv) Consolidated Balance Sheets at September 30, 2021, and December 31, 2020; (v) Consolidated Statements of Cash Flows for the nine months ended September 30, 2021 and 2020; (vi) Consolidated Statements of Changes in Equity for the three and nine months ended September 30, 2021 and 2020; and (vii) Notes to Consolidated Financial Statements.
Pursuant to the requirements of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
