ONEOK INC /NEW/ - Annual Report: 2019 (Form 10-K)

---

---

---

---

---

---

•

Operate in a safe, reliable, environmentally responsible and sustainable manner - environmental, safety and health continues to be a primary focus for us, and our emphasis on personal and process safety has produced improvements in the key indicators we track. We also continue to look for ways to reduce our environmental impact by conserving resources and utilizing more efficient technologies. In 2019, we were added to the Dow Jones Sustainability North America Index, which recognizes companies for industry-leading environmental, social and governance performance;

•

Pursue organic investments in our existing operating regions to support earnings growth - we expect our investment in capital projects to create stable earnings growth that positions us to grow our dividend. In 2019, we paid dividends of $3.53 per share, an increase of 9% compared with the prior year. Our dividend increase and expected future dividend growth is due primarily to earnings growth from capital projects;

•

Manage our balance sheet and maintain investment-grade credit ratings - we seek to maintain investment-grade credit ratings, fund capital-growth projects and begin to pay down debt. We expect to benefit from increasing cash flows from operations in 2020, which we expect to reduce leverage and fund capital-growth projects. At December 31, 2019, we had no borrowings outstanding under our $2.5 Billion Credit Agreement, $220 million of commercial paper outstanding and $21 million of cash and cash equivalents; and

•	Attract, select, develop, motivate, challenge and retain a diverse group of employees to support strategy execution - we continue to execute on our recruiting strategy that targets professional and field personnel in our operating areas. We also continue to focus on employee development efforts with our current employees and monitor our benefits and compensation package to remain competitive.

---

•	Natural Gas Gathering and Processing;

•	Natural Gas Liquids; and

•	Natural Gas Pipelines.

•	18,900 miles of natural gas gathering pipelines;

•	ten natural gas processing plants with 1.0 Bcf/d of processing capacity in the Mid-Continent region, and 12 natural gas processing plants with 1.5 Bcf/d of processing capacity in the Rocky Mountain region; and

•	14 MBbl/d of NGL fractionation capacity at various natural gas processing plants.

---

•

POP with fee contracts with no producer take-in-kind rights - We purchase raw natural gas and charge contractual fees for providing midstream services, which include gathering, treating, compressing and processing the producer’s natural gas. After performing these services, we sell the commodities and remit a portion of the commodity sales proceeds to the producer less our contractual fees. This type of contract represented 63% and 60% of supply volumes in this segment for 2019 and 2018, respectively.

•

POP with fee contracts with producer take-in-kind rights - We purchase a portion of the raw natural gas stream, charge fees for providing the midstream services listed above, return primarily the residue natural gas to the producer, sell the remaining commodities and remit a portion of the commodity sales proceeds to the producer less our contractual fees. This type of contract represented 33% and 36% of supply volumes in this segment for 2019 and 2018, respectively.

•	Fee-only - Under this type of contract, we charge a fee for the midstream services we provide, based on volumes gathered, processed, treated and/or compressed. Our fee-only contracts represented 4% of supply volumes in this segment in 2019 and 2018.

•	49% ownership interest in Bighorn Gas Gathering, which gathers dry natural gas produced in the Powder River Basin;

•	42.6% ownership interest in Fort Union Gas Gathering, which gathers dry natural gas produced in the Powder River Basin and delivers it to the interstate pipeline system;

•	35% ownership interest in Lost Creek Gathering Company, which gathers natural gas produced from conventional dry natural gas wells in the Wind River Basin of central Wyoming and delivers it to the interstate pipeline system; and

•	10.2% ownership interest in Venice Energy Services Co., a natural gas processing facility near Venice, Louisiana.

---

•	8,380 miles of gathering pipelines with peak capacity of 1,820 MBbl/d, including 5,550 miles of FERC-regulated pipelines with peak capacity of 920 MBbl/d;

•	4,490 miles of distribution pipelines with peak capacity of 1,400 MBbl/d, including 4,460 miles of FERC-regulated pipelines with peak capacity of 1,360 MBbl/d;

•	eight NGL fractionators with combined operating capacity of 870 MBbl/d (includes interests in our proportional share of operating capacity), including 520 MBbl/d in the Mid-Continent region and 350 MBbl/d in the Gulf Coast region;

•	one isomerization unit with operating capacity of 10 MBbl/d;

•	one ethane/propane splitter with operating capacity of 40 MBbl/d;

•	six NGL storage facilities with operating storage capacity of 20 MMBbl; and

•	eight NGL product terminals.

---

•	gathering pipelines, including expansions, with combined operating capacity of 880 MBbl/d;

•	the MB-5 fractionator in the Gulf Coast with operating capacity of 125 MBbl/d;

•	remaining fractionation capacity on the MB-4 fractionator in the Gulf Coast of 50 MBbl/d; and

•	additional fractionation capacity in the Mid-Continent of 65 MBbl/d.

•

Exchange services - We utilize our assets to gather, transport, treat and fractionate unfractionated NGLs, thereby converting them into marketable NGL products delivered to a market center or customer-designated location. Many of these exchange volumes are under contracts with minimum volume commitments that provide a minimum level of revenues regardless of volumetric throughput. Our exchange services activities are primarily fee-based and include some rate-regulated tariffs; however, we also capture certain product price differentials through the fractionation process.

•

Transportation and storage services - We transport NGL products and refined petroleum products, primarily under FERC-regulated tariffs. Tariffs specify the maximum rates we may charge our customers and the general terms and conditions for transportation service on our pipelines. Our storage activities consist primarily of fee-based NGL storage services at our Mid-Continent and Gulf Coast storage facilities.

•

Optimization and marketing - We utilize our assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials through the purchase and sale of NGLs and NGL products. We primarily transport NGL products between Conway, Kansas, and Mont Belvieu, Texas, to capture the location price differentials between the two market centers. Our marketing activities also include utilizing our NGL storage facilities to capture seasonal price differentials. A growing portion of our marketing activities serves truck and rail markets. Our isomerization activities capture the price differential when normal butane is converted into the more valuable iso-butane at our isomerization unit in Conway, Kansas.

•	our NGL gathering pipelines were 78% in both years;

•	our NGL distribution pipelines were 63% and 59%; and

•	our NGL fractionators were 84% and 85%.

•	50% ownership interest in Overland Pass Pipeline Company, which operates an interstate NGL pipeline system extending 760 miles, originating in Wyoming and Colorado and terminating in Kansas;

•	50% ownership interest in Chisholm Pipeline Company, which operates an interstate NGL pipeline system extending 185 miles from origin points in Oklahoma and terminating in Kansas; and

•	50% ownership interest in Heartland Pipeline Company, which operates a terminal and pipeline system that transports refined petroleum products in Kansas, Nebraska and Iowa.

---

•	Midwestern Gas Transmission, which is a bidirectional system that interconnects with Tennessee Gas Transmission Company’s pipeline near Portland, Tennessee, and with several interstate pipelines that have access to both the Utica Shale and the Marcellus Shale at the Chicago Hub near Joliet, Illinois;

•	Viking Gas Transmission, which is a bidirectional system that interconnects with a TransCanada Corporation pipeline at the United States border near Emerson, Canada, and ANR Pipeline Company near Marshfield, Wisconsin;

•	Guardian Pipeline, which interconnects with several pipelines at the Chicago Hub near Joliet, Illinois, and with local natural gas distribution companies in Wisconsin; and

•	OkTex Pipeline, which has interconnections with several pipelines in Oklahoma, Texas and New Mexico.

---

•	1,500 miles of FERC-regulated interstate natural gas pipelines with 3.5 Bcf/d of peak transportation capacity;

•	5,100 miles of state-regulated intrastate transmission pipelines with peak transportation capacity of 4.3 Bcf/d; and

•	six underground natural gas storage facilities with 52.2 Bcf of total active working natural gas storage capacity.

•

Firm service - Customers reserve a fixed quantity of pipeline capacity for a specified period of time, which obligates the customer to pay regardless of usage. Under this type of contract, the customer pays a monthly fixed fee and incremental fees, known as commodity charges, which are based on the actual volumes of natural gas they transport or store. Under the firm service contract, the customer generally is guaranteed access to the capacity they reserve.

•	Interruptible service - Under interruptible service transportation agreements, the customer may utilize available capacity after firm service requests are satisfied. The customer is not guaranteed use of our pipelines unless excess capacity is available.

•	Firm service - Customers reserve a specific quantity of storage capacity, including injection and withdrawal rights, and generally pay fixed fees based on the quantity of capacity reserved plus an injection and withdrawal fee. Firm storage contracts typically have terms longer than one year.

•	Park-and-loan service - An interruptible storage service offered to customers providing the ability to park (inject) or loan (withdraw) natural gas into or out of our storage, typically for monthly or seasonal terms. Customers reserve the

---

•	50% ownership interest in Northern Border Pipeline, which owns a FERC-regulated interstate pipeline that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana, and the Williston Basin in North Dakota to a terminus near North Hayden, Indiana.

•	50% ownership interest in Roadrunner, a bidirectional pipeline, which has the capacity to transport 570 MMcf/d of natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas, and has capacity to transport approximately 1.0 Bcf/d of natural gas from the Delaware Basin to the Waha area. We are the operator of Roadrunner.

---

•	quality of services provided;

•	producer drilling activity;

•	proceeds remitted and/or fees charged under our contracts;

•	proximity of our assets to natural gas and NGL supply areas and markets;

•	location of our assets relative to those of our competitors;

•	efficiency and reliability of our operations;

•	receipt and delivery capabilities for natural gas and NGLs that exist in each pipeline system, plant, fractionator and storage location;

•	the petrochemical industry’s level of capacity utilization and feedstock requirements;

•	current and forward natural gas and NGL prices; and

•	cost of and access to capital.

---

---

---

---

•	demand and prices for natural gas, NGLs and crude oil;

•	producers’ access to capital;

•	producers’ finding and development costs of reserves;

•	producers’ ability to obtain necessary permits, drilling rights and surface access in a timely manner and on reasonable terms;

•	natural gas field characteristics and production performance; and

•	capacity constraints on natural gas, crude oil and NGL infrastructure from the producing areas and our facilities.

---

---

•	projects may require significant capital expenditures, which may exceed our estimates, and involve numerous regulatory, environmental, political, legal and weather-related uncertainties;

•	projects may increase demand for labor, materials and rights of way, which may, in turn, affect our costs and schedule;

•	we may be unable to obtain new rights of way to connect new natural gas or NGL supplies to our existing gathering or transportation pipelines;

•	if we undertake these projects, we may not be able to complete them on schedule or at the budgeted cost;

•	our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project;

•	we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize;

•

opposition from environmental groups, landowners, tribal groups, local groups and other advocates could result in organized protests, attempts to block or sabotage our construction activities or operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the construction or operation of our assets; and

•	we may be required to rely on third parties downstream of our facilities to have available capacity for our delivered natural gas or NGLs, which may not yet be operational.

•	overall domestic and global economic conditions;

•	relatively minor changes in the supply of, and demand for, domestic and foreign energy;

•	market uncertainty;

•	the availability and cost of third-party transportation, natural gas processing and fractionation capacity;

•	the level of consumer product demand and storage inventory levels;

•	ethane rejection;

•	geopolitical conditions impacting supply and demand for natural gas, NGLs and crude oil;

•	weather conditions;

•	domestic and foreign governmental regulations and taxes;

•	the price and availability of alternative fuels;

•	speculation in the commodity futures markets;

•	the effects of imports and exports on the price of natural gas, crude oil, NGL and liquefied natural gas;

•	the effect of worldwide energy-conservation measures;

•	the impact of new supplies, new pipelines, processing and fractionation facilities on location price differentials; and

•	technology and improved efficiency impacting supply and demand for natural gas, NGLs and crude oil.

---

•	the value of the commodities sold under POP with fee contracts of which we retain a portion of the sales proceeds;

•	the price differentials between the individual NGL products with respect to our NGL transportation and fractionation agreements;

•	the location price differentials in the price of natural gas and NGLs;

•	the seasonal price differentials in natural gas and NGLs related to our storage operations;

•	the price risk related to electric costs to operate our facilities, primarily in Texas; and

•	the fuel costs and the value of the retained fuel in-kind in our natural gas pipelines and storage operations.

•	controlling our plants and pipelines with industrial control systems including Supervisory Control and Data Acquisition (SCADA);

•	collecting and storing customer, employee, investor and other stakeholder information and data;

•	processing transactions;

•	summarizing and reporting results of operations;

•	hosting, processing and sharing confidential and proprietary research, business plans and financial information;

•	complying with regulatory, legal, financial or tax requirements;

•	providing data security; and

•	other processes necessary to manage our business.

---

•	the Clean Air Act and analogous state laws that impose obligations related to air emissions;

•	the Clean Water Act and analogous state laws that regulate discharge of wastewater from our facilities to state and federal waters;

•	the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal; and

•	the federal Resource Conservation and Recovery Act and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities.

---

•	regulatory approval and review of certain of our rates, operating terms and conditions of service;

•	the types of services we may offer our counterparties;

•	construction of new facilities;

•	the integrity, safety and security of facilities and operations;

•	acquisition, extension or abandonment of services or facilities;

•	reporting and information posting requirements;

•	maintenance of accounts and records; and

•	relationships with affiliate companies involved in all aspects of the natural gas and energy businesses.

---

---

•	inaccurate assumptions about volumes, revenues and costs, including potential synergies;

•	an inability to integrate successfully the businesses we acquire;

•	decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;

•	a significant increase in our interest expense and/or financial leverage if we incur additional debt to finance the acquisition;

•	the assumption of unknown liabilities for which we are not indemnified, our indemnity is inadequate or our insurance policies may exclude from coverage;

•	an inability to hire, train or retain qualified personnel to manage and operate the acquired business and assets;

•	limitations on rights to indemnity from the seller;

•	inaccurate assumptions about the overall costs of equity or debt;

•	the diversion of management’s and employees’ attention from other business concerns;

•	unforeseen difficulties operating in new product areas or new geographic areas;

•	increased regulatory burdens;

•	customer or key employee losses at an acquired business; and

•	increased regulatory requirements.

---

---

---

•	make it more difficult for us to satisfy our obligations with respect to senior notes and other indebtedness due to the increased debt-service obligations, which could, in turn, result in an event of default on such other indebtedness or the senior notes;

•	impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes;

•	diminish our ability to withstand a downturn in our business or the economy;

•	require us to dedicate a substantial portion of our cash flows from operations to debt-service payments, reducing the availability of cash for working capital, capital expenditures, acquisitions, dividends or general corporate purposes;

•	limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

•	place us at a competitive disadvantage compared with our competitors that have proportionately less debt and fewer guarantee obligations.

---

•	the guarantor incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or the guarantor contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or

•	the guarantor did not receive fair consideration or reasonable equivalent value for issuing the guarantee and, at the time it issued the guarantee, the guarantor:

–	was engaged or about to engage in a business or transaction for which its remaining assets constituted unreasonably small capital; or

•	the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation;

•	the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature; or

•	it could not pay its debts as they become due.

---

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

---

---

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

---

---

---

•	Natural Gas Gathering and Processing - an increase of $95.5 million due primarily to natural gas volume growth, offset partially by a decrease of $20.9 million due primarily to lower realized NGL and natural gas prices, net of hedges;

---

•	Natural Gas Liquids - an increase of $148.1 million in exchange services due primarily to higher volumes and average fee rates, offset partially by a decrease of $60.2 million in optimization and marketing due primarily to wider location price differentials in the prior year; and

•	Natural Gas Pipelines - an increase of $56.5 million from higher transportation services, offset partially by a decrease of $9.1 million from lower net retained fuel and timing of equity gas sales; offset partially by

•	an increase of $75.9 million in operating costs due primarily to higher employee-related costs associated with labor and benefits, spending on routine maintenance projects and ad valorem taxes due to the growth of our operations; and

•	an increase of $47.9 million in depreciation expense due to capital projects placed in service.

---

•	an increase of $95.5 million due primarily to natural gas volume growth in the Williston Basin and STACK and SCOOP areas, offset partially by natural production declines; and

•	a decrease of $4.9 million in operating costs due primarily to lower outside services and materials and supplies, offset partially by higher employee-related costs and ad valorem taxes due primarily to the growth of our operations; offset partially by

•	a decrease of $20.9 million due primarily to lower realized NGL and natural gas prices, net of hedges; and

•	a decrease of $6.7 million due primarily to lower equity in net earnings from investments due to a decrease in supply volumes in the dry natural gas area of the Powder River Basin.

---

•

an increase of $148.1 million in exchange services due to $150.2 million in higher volumes primarily in the Rocky Mountain region, the Permian Basin and the STACK and SCOOP areas, and $91.5 million in higher average fee rates primarily in the Permian Basin and the Rocky Mountain region, offset partially by $64.9 million due primarily to higher third-party transportation and fractionation costs, $25.0 million due primarily to narrower product price differentials and $5.8 million related to higher unfractionated NGLs in inventory; offset partially by

•

a decrease of $60.2 million in optimization and marketing due primarily to a decrease of $93.8 million related to wider location price differentials in the prior year, particularly in the third quarter 2018, and $5.1 million in lower earnings related primarily to product price differentials, offset partially by higher marketing earnings of $38.5 million related primarily to the sale of NGL products previously held in inventory; and

•	an increase of $56.1 million in operating costs due primarily to higher employee-related costs associated with labor and benefits due to the growth of our operations, and spending on routine maintenance projects.

---

•	an increase of $56.5 million from higher transportation services due primarily to firm transportation capacity contracted due to our completed expansion projects; and

•	an increase of $4.9 million from higher equity in net earnings due primarily to firm transportation capacity contracted on Roadrunner; offset partially by

•	an increase of $11.6 million in operating costs due primarily to employee-related costs associated with labor and benefits and ad valorem taxes due to the growth of our operations; and

•	a decrease of $9.1 million from lower net retained fuel and timing of equity gas sales.

---

---

---

---

---

---

---

---

---

•	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 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 or extended periods of ethane rejection;

•	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;

•	demand for our services and products in the proximity of our facilities;

•	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 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;

•	economic climate and growth in the geographic areas in which we do business;

•	the timing and extent of changes in energy commodity prices;

•	the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances;

•	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;

•	the profitability of assets or businesses acquired or constructed by us;

•	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;

•	risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties;

•	the uncertainty of estimates, including accruals and costs of environmental remediation;

•	changes in demand for the use of natural gas, NGLs and crude oil because of market conditions caused by concerns about climate change;

•	the impact of uncontracted capacity in our assets being greater or less than expected;

•	the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines;

•	the efficiency of our plants in processing natural gas and extracting and fractionating NGLs;

---

•	our ability to control construction costs and completion schedules of our pipelines and other projects;

•	the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, climate change initiatives and authorized rates of recovery of natural gas and natural gas transportation costs;

•	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 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 PHMSA, the EPA and the CFTC;

•	difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or pipelines;

•	the capital-intensive nature of our businesses;

•	the mechanical integrity of facilities operated;

•	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 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;

•	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;

•	actions by rating agencies concerning our credit;

•	our ability to access capital at competitive rates or on terms acceptable to us;

•	the impact and outcome of pending and future litigation;

•	performance of contractual obligations by our customers, service providers, contractors and shippers;

•	our ability to control operating costs and make cost-saving changes;

•	the impact of recently issued and future accounting updates and other changes in accounting policies;

•	the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks;

•	the risk inherent in the use of information systems in our respective businesses and those of our counterparties and service providers, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting;

•	the impact of potential impairment charges; and

•	the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference.

---

•	a $0.01 per gallon change in the composite price of NGLs, excluding ethane, would change adjusted EBITDA for the years ending December 31, 2020 and 2021, by $2.5 million and $3.0 million, respectively;

•	a $1.00 per barrel change in the price of crude oil would change adjusted EBITDA for the years ending December 31, 2020 and 2021, by $1.5 million and $1.8 million, respectively; and

•	a $0.10 per MMBtu change in the price of residue natural gas would change adjusted EBITDA for the years ending December 31, 2020 and 2021, by $6.1 million and $7.1 million, respectively.

---

---

---

---

---

---

---

---

---

---

---

---

---

A.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

---

•	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 December 31, 2019, 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 accounted for as hedges.

---

---

---

---

---

---

---

---

B.	FAIR VALUE MEASUREMENTS

---

C.	RISK-MANAGEMENT AND HEDGING ACTIVITIES USING DERIVATIVES

•	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.

---

---

---

E.	GOODWILL AND INTANGIBLE ASSETS

---

F.	DEBT

---

---

---

G.	EQUITY

---

H.	ACCUMULATED OTHER COMPREHENSIVE LOSS

---

I.	EARNINGS PER SHARE

---

J.	SHARE-BASED PAYMENTS

---

---

K.	EMPLOYEE BENEFIT PLANS

---

---

---

---

---

L.	INCOME TAXES

---

---

M.	UNCONSOLIDATED AFFILIATES

---

---

N.	COMMITMENTS AND CONTINGENCIES

O.	LEASES

---

---

P.	REVENUES

---

---

Q.	SEGMENTS

•	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 operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities.

---

---

---

R.	QUARTERLY FINANCIAL DATA (UNAUDITED)

---

S.	SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

•	we are referred to as “Parent Issuer and Guarantor”

•	ONEOK Partners is referred to as “Subsidiary Issuer and Guarantor”

•	the Intermediate Partnership is referred to as “Guarantor Subsidiary” and

•	the “Non-Guarantor Subsidiaries” are all subsidiaries other than the Guarantor Subsidiary and Subsidiary Issuer and Guarantor.

---

---

---

---

---

---

---

---

---

---

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

---

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

---

---

---

---

---

---

---

---

---