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Provide reliable energy and energy-related services in a safe and environmentally responsible manner to our stakeholders through our ownership in ONEOK Partners - environmental, safety and health issues continue 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;

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Maximize dividend payout while maintaining prudent financial strength and flexibility - during 2014, cash dividends paid per share increased 44 percent compared with the prior year. During 2014, ONEOK Partners’ cash distributions increased by 14 cents per unit, an increase of approximately 5 percent compared with 2013. ONEOK Partners announced new capital projects and acquisitions of $2.2 billion, increasing its total growth program, which began in 2010, to approximately $8.0 billion to $8.9 billion. These projects are expected to meet the needs of NGL and natural gas producers in the Williston Basin and NGL-rich areas of the Powder River Basin in the Rocky Mountain region; the Cana-Woodford Shale, Springer Shale, Stack and SCOOP areas in Oklahoma, and the Permian Basin in Texas and New Mexico; and provide additional natural gas liquids infrastructure in the Mid-Continent and Gulf Coast areas, which will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand. When completed, these projects are anticipated to provide additional earnings and cash flows. Our strategy is to distribute the majority of our cash flows in excess of debt service, income taxes and other operating needs in the form of dividends. ONEOK Partners’ balance sheet remains strong, and ONEOK Partners will seek to maintain investment-grade credit ratings; and

•	Attract, select, develop 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.

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•	Natural Gas Gathering and Processing;

•	Natural Gas Liquids; and

•	Natural Gas Pipelines.

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POP with fee - ONEOK Partners retains a percentage of the proceeds from the sale of residue gas, condensate and/or NGLs, and charges fees for gathering, treating, compressing and/or processing the producer’s natural gas. POP with fee contracts expose ONEOK Partners to commodity price risk. This type of contract represented approximately 87 percent and 85 percent of contracted volumes in this segment for 2014 and 2013, respectively. There are a variety of factors that directly affect ONEOK Partners’ POP revenues, including:

–	the natural gas, crude oil and NGL prices received for its retained products;

–	the percentage of NGL, condensate and residue natural gas sales proceeds retained by ONEOK Partners that it receives as payment for the services it provides;

–	the composition of the NGLs produced;

–	volume produced that affects its fee revenue; and

–	transportation and fractionation costs incurred on the NGLs, condensate and natural gas it retains.

•	Fee - ONEOK Partners is paid a fee for the services it provides, based on volumes gathered, processed, treated and/or compressed. ONEOK Partners’ fee-based contracts represented approximately 13 percent and 15 percent of contracted volumes in this segment for 2014 and 2013, respectively.

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•	49 percent ownership interest in Bighorn Gas Gathering, which operates a major coal-bed methane gas gathering system serving a broad production area in northeast Wyoming;

•	37 percent ownership interest in Fort Union Gas Gathering, which gathers coal-bed methane gas produced in the Powder River Basin and delivers it into the interstate pipeline grid;

•	35 percent ownership interest in Lost Creek Gathering Company, which gathers natural gas produced from conventional wells in the Wind River Basin of central Wyoming and delivers natural gas into the interstate pipeline grid; and

•	10 percent ownership interest in Venice Energy Services Co., a natural gas processing complex near Venice, Louisiana.

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•	quality of services provided;

•	producer drilling activity;

•	products retained and/or fees charged under its gathering and processing contracts;

•	location of its gathering systems relative to those of its competitors;

•	location of its gathering systems relative to drilling activity;

•	operating pressures maintained on its gathering systems;

•	efficiency and reliability of its operations;

•	delivery capabilities for natural gas and natural gas liquids that exist in each system and plant location; and

•	cost of capital.

•	investing capital to construct and expand its assets;

•	improving natural gas processing efficiency;

•	reducing operating costs;

•	consolidating assets;

•	decreasing commodity price exposure; and

•	renegotiating low-margin contracts.

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•	ONEOK Partners’ exchange-services activities utilize its assets to gather, fractionate and/or treat unfractionated NGLs for a fee, thereby converting them into marketable NGL products that are stored and shipped to a market center or customer-designated location. Many of these exchange volumes are under contracts with minimum volume commitments.

•	ONEOK Partners’ optimization and marketing activities utilize its assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials.  It transports NGL products between Conway, Kansas, and Mont Belvieu, Texas, to capture the location price differentials between the two market centers.  Its natural gas liquids

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•	ONEOK Partners’ pipeline transportation services transport unfractionated NGLs, NGL products and refined petroleum products, primarily under FERC-regulated tariffs.  Tariffs specify the maximum rates it charges customers and the general terms and conditions for NGL transportation service on its pipelines.

•	ONEOK Partners’ isomerization activities capture the price differential when normal butane is converted into the more valuable iso-butane at its isomerization unit in Conway, Kansas.  Iso-butane is used in the refining industry to increase the octane of motor gasoline.

•	ONEOK Partners’ storage activities consist primarily of fee-based NGL storage services at its Mid-Continent and Gulf Coast storage facilities.

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•	quality of services provided;

•	producer drilling activity;

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

•	fees charged under its contracts;

•	current and forward NGL prices;

•	location of its gathering systems relative to its competitors;

•	location of its gathering systems relative to drilling activity;

•	proximity to NGL supply areas and markets;

•	efficiency and reliability of its operations;

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

•	cost of capital.

•	Midwestern Gas Transmission, which is a bi-directional system that interconnects with Tennessee Gas Transmission Company’s pipeline near Portland, Tennessee, and with several interstate pipelines at the Chicago Hub near Joliet, Illinois;

•	Viking Gas Transmission, which is a bi-directional system, interconnects with a TransCanada pipeline near Emerson, Manitoba, 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 interconnects in Oklahoma, Texas and New Mexico.

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Firm service - Customers can reserve a fixed quantity of pipeline or storage capacity for the term of their contract. Under this type contract, the customer pays a fixed fee for a specified quantity regardless of their actual usage.  The customer then typically pays incremental fees, known as commodity charges, that are based upon the actual volume of natural gas they transport or store, and/or ONEOK Partners may retain a specified volume of natural gas in-kind for fuel. Under the firm-service contract, the customer generally is guaranteed access to the capacity they reserve; and

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Interruptible service - Customers with interruptible service transportation and storage agreements may utilize available capacity after firm-service requests are satisfied or on an as-available basis.  Interruptible service customers typically are assessed fees, such as a commodity charge, based on their actual usage, and/or ONEOK Partners may retain a specified volume of natural gas in-kind for fuel.  Under the interruptible service contract, the customer is not guaranteed use of ONEOK Partners’ pipelines and storage facilities unless excess capacity is available.

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•	an evaluation on whether hazardous natural gas liquids and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;

•	a review of all natural gas and hazardous natural gas liquids gathering pipeline exemptions;

•	a verification of records for pipelines in Class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and

•	a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

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

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

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•	the extent to which acquisitions and investment opportunities become available;

•	success in bidding for the opportunities that do become available;

•	regulatory approval, if required, of the acquisitions or investments on favorable terms; and

•	access to capital, including the ability to use our or equity in acquisitions or investments, and the terms upon which we obtain capital.

•	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;

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

•	increased regulatory requirements.

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•	controlling ONEOK Partners’ 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 or tax requirements;

•	providing data security; and

•	handling other processing necessary to manage our business.

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•	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;

•	overall domestic and global economic conditions;

•	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; and

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

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•	the value of the NGLs and natural gas it receives in exchange for the natural gas gathering and processing services it provides;

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

•	the location price differentials in the price of natural gas and NGLs with respect to ONEOK Partners’ natural gas and NGL transportation businesses;

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

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

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

•	producers’ finding and developing costs of reserves;

•	producers’ desire and ability to obtain necessary permits in a timely and economic manner;

•	natural gas field characteristics and production performance;

•	surface access and infrastructure issues; and

•	capacity constraints on natural gas, crude oil and natural gas liquids infrastructure from the producing areas and ONEOK Partners’ facilities.

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•	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 waste water from ONEOK Partners’ facilities to state and federal waters;

•	the federal 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 ONEOK Partners or locations to which ONEOK Partners has 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 ONEOK Partners’ facilities.

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•	rates, operating terms and conditions of service;

•	the types of services ONEOK Partners may offer it customers;

•	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.

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•	make it more difficult to satisfy its obligations with respect to its senior notes and other indebtedness, which could in turn result in an event of default on such other indebtedness or its senior notes;

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

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

•	require it to dedicate a substantial portion of its cash flow from operations to debt-service payments, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, distributions to partners and general partnership purposes;

•	limit its flexibility in planning for, or reacting to, changes in its business and the industry in which it operates; and

•	place it at a competitive disadvantage compared with its competitors that have proportionately less debt.

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

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

–	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.

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•	approximately 11,300 miles and 7,400 miles of natural gas gathering pipelines in the Mid-Continent and Rocky Mountain regions, respectively;

•	nine natural gas processing plants with approximately 785 MMcf/d of processing capacity in the Mid-Continent region, and 10 natural gas processing plants with approximately 665 MMcf/d of processing capacity in the Rocky Mountain region; and

•	approximately 30 MBbl/d of natural gas liquids fractionation capacity at various natural gas processing plants in the Mid-Continent and Rocky Mountain regions.

•	four additional natural gas processing plants in the Rocky Mountain region, which will provide approximately 530 MMcf/d of combined processing capacity;

•	projects to increase natural gas compression at existing facilities in the Rocky Mountain region, which will provide approximately 100 MMcf/d of processing capacity; and

•	one natural gas processing plant in the Mid-Continent region, with approximately 200 MMcf/d of processing capacity.

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•	approximately 2,800 miles of non-FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 800 MBbl/d;

•	approximately 170 miles of non-FERC-regulated natural gas liquids distribution pipelines with peak transportation capacity of approximately 66 MBbl/d;

•	approximately 4,270 miles of FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 633 MBbl/d;

•	approximately 4,100 miles of FERC-regulated natural gas liquids and refined petroleum products distribution pipelines with peak capacity of 900 MBbl/d;

•	one natural gas liquids fractionator, located in Oklahoma, with operating capacity of approximately 210 MBbl/d; two natural gas liquids fractionators, located in Kansas, with combined operating capacity of 280 MBbl/d; and two natural gas liquids fractionators, located in Texas, with combined operating capacity of 150 MBbl/d;

•	80 percent ownership interest in one natural gas liquids fractionator in Texas with ONEOK Partners’ proportional share of operating capacity of approximately 128 MBbl/d;

•	interest in one natural gas liquids fractionator in Kansas with ONEOK Partners’ proportional share of operating capacity of approximately 11 MBbl/d;

•	one isomerization unit in Kansas with operating capacity of 9 MBbl/d;

•	six natural gas liquids storage facilities in Oklahoma, Kansas and Texas with operating storage capacity of approximately 23.2 MMBbl;

•	eight natural gas liquids product terminals in Missouri, Nebraska, Iowa and Illinois;

•	above- and below-ground storage facilities associated with ONEOK Partners’ FERC-regulated natural gas liquids pipeline operations in Iowa, Illinois, Nebraska and Kansas with combined operating capacity of 978 MBbl; and

•	one ethane/propane splitter in Texas with operating capacity of 32 MBbl/d of purity ethane and 8 MBbl/d of propane.

•	its non-FERC-regulated natural gas liquids gathering pipelines were approximately 62 percent and 69 percent;

•	its FERC-regulated natural gas liquids gathering pipelines were approximately 79 percent and 71 percent;

•	its FERC-regulated natural gas liquids distribution pipelines were approximately 47 percent and 58 percent;

•	its natural gas liquids fractionators were approximately 70 percent and 78 percent; and

•	its average contracted natural gas liquids storage volumes were approximately 69 percent and 72 percent of storage capacity.

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•	approximately 1,500 miles of FERC-regulated interstate natural gas pipelines with approximately 3.2 Bcf/d of peak transportation capacity;

•	approximately 5,200 miles of state-regulated intrastate transmission pipelines with peak transportation capacity of approximately 3.2 Bcf/d; and

•	approximately 51.7 Bcf of total active working natural gas storage capacity.

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

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

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•	the Garden Creek III natural gas processing plant, which was completed in October 2014;

•	the Garden Creek II natural gas processing plant, which was completed in August 2014;

•	the Canadian Valley natural gas processing plant, which was completed in March 2014;

•	the acquisition of the remaining 30 percent undivided interest in the Maysville, Oklahoma, natural gas processing facility, which was acquired in December 2013;

•	the acquisition of the Sage Creek natural gas processing plant in Wyoming in September 2013; and

•	the Stateline II natural gas processing plant, which was completed in April 2013.

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an increase of $147.6 million due primarily to natural gas volume growth in the Williston Basin and Cana-Woodford Shale and increased ownership of the Maysville, Oklahoma, natural gas processing plant resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, higher NGL volumes sold and higher fees, offset partially by wellhead freeze-offs due to severely cold weather in the first quarter 2014;

•	an increase of $11.3 million due primarily to higher net realized natural gas and NGL prices; and

•	an increase of $8.8 million due primarily to changes in contract mix; offset partially by

•	a decrease of $6.4 million due to a condensate contract settlement in 2013.

•	an increase of $46.3 million in higher materials and supplies, and outside service expenses; and

•	an increase of $21.2 million in employee-related costs due to higher labor and employee benefit costs; offset partially by

•	a decrease of $3.2 million due to lower ad valorem tax expense resulting from capitalized taxes related to construction projects.

•	an increase of $100.1 million due primarily to volume growth in the Williston Basin from the Stateline I and Stateline II natural gas processing plants, and increased well connections resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, higher NGL volumes sold and higher fees; and

•	an increase of $6.4 million due to a contract settlement in 2013; offset partially by

•	a decrease of $41.7 million due primarily to lower net realized NGL prices;

•	a decrease of $13.4 million due primarily to changes in contract mix and terms associated with volume growth; and

•	a decrease of $3.5 million due to lower dry natural gas volumes gathered as a result of continued declines in coal-bed methane production in the Powder River Basin.

•	an increase of $16.8 million in higher materials and supplies, and outside service expenses;

•	an increase of $10.3 million in employee-related costs due to higher labor and employee benefit costs, offset partially by lower incentive compensation costs; and

•	an increase of $2.2 million due to higher ad valorem taxes.

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•	the West Texas LPG acquisition, which was completed in November 2014;

•	the Niobrara NGL Lateral, which was completed in September 2014;

•	the Bakken NGL Pipeline expansion, Phase I, which was completed in September 2014;

•	the Sterling III Pipeline and reconfigurations to Sterling I and II, which were completed in March 2014;

•	the Ethane/Propane Splitter, which was completed in March 2014;

•	the MB-2 Fractionator, which was completed in December 2013;

•	the Sage Creek NGL infrastructure, which was completed in September 2013;

•	the Bakken NGL Pipeline, which was completed in April 2013;

•	the expansion of the Overland Pass Pipeline, which was completed in the second quarter 2013; and

•	the Ethane Header Pipeline, which was completed in April 2013.

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•	an increase of $157.4 million in exchange-services and transportation margins, which resulted from increased volumes from new plants connected in the Williston Basin and Mid-Continent region, and higher fees for exchange-services activities resulting from contract renegotiations, offset partially by lower volumes from the termination of a contract;

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an increase of $79.8 million in optimization and marketing margins, which resulted from a $31.4 million increase due primarily to wider realized NGL product price differentials; a $25.2 million increase in marketing margins related primarily to increased weather-related seasonal demand for propane during the first quarter 2014, and marketing and truck and rail activities in the second, third and fourth quarters 2014; and a $23.2 million increase due primarily to significantly wider NGL location price differentials, primarily related to increased weather-related seasonal demand for propane during the first quarter 2014, offset partially by lower optimization volumes in the second, third and fourth quarters 2014 when differentials narrowed; and

•	an increase of $22.8 million related to higher isomerization volumes, resulting from the wider NGL product price differential between normal butane and iso-butane; offset partially by

•	a decrease of $18.3 million resulting from the impact of ethane rejection, which resulted in lower NGL volumes; and

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•	a decrease of $6.0 million due to the impact of lower operational measurement gains.

•	an increase of $20.1 million due to higher outside services expenses associated primarily with scheduled maintenance and the growth of operations related to completed capital projects;

•	an increase of $15.5 million due to higher ad valorem taxes related to its completed capital projects;

•	an increase of $14.9 million due to higher employee-related costs due primarily to higher labor and employee benefit costs; and

•	an increase of $3.4 million due to higher chemical, materials and supplies expense.

•	a decrease of $162.7 million in optimization and marketing margins, which resulted from a $202.5 million decrease due primarily to significantly narrower NGL location price differentials. This decrease was offset partially by an increase of $35.7 million due primarily to more favorable NGL product price differentials;

•	a decrease of $48.8 million resulting from the impact of ethane rejection, which resulted in lower NGL volumes; and

•	a decrease of $22.4 million related to lower isomerization volumes, resulting from the narrower price differential between normal butane and iso-butane; offset partially by

•	an increase of $166.5 million in exchange-services margins, which resulted from higher NGL volumes gathered, contract renegotiations for higher fees for ONEOK Partners’ NGL exchange-services activities and higher revenues from customers with minimum volume obligations;

•	an increase of $19.5 million due to the impact of operational measurement gains of approximately $9.7 million in 2013, compared with losses of approximately $9.8 million in 2012; and

•	an increase of $10.5 million in storage margins due primarily to contract renegotiations.

•	an increase of $5.4 million due to higher ad valorem taxes related to ONEOK Partners’ completed capital projects; and

•	an increase of $5.0 million in employee-related costs due to higher labor and employee benefit costs due to the growth of ONEOK Partners’ operations related to its completed capital projects, offset partially by lower incentive compensation costs.

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•	an increase of $26.3 million due to higher transportation revenues primarily from increased rates on intrastate pipelines, higher contracted capacity and rates on Midwestern Gas Transmission and increased interruptible transportation revenues from higher natural gas volumes transported;

•	an increase of $17.6 million from higher short-term natural gas storage services due to higher park-and-loan activity as a result of weather-related seasonal demand primarily in the first quarter 2014 and greater capacity available for such services;

•	an increase of $5.1 million due to increased park-and-loan services on our interstate pipelines as a result of weather-related seasonal demand in the first quarter 2014;

•	an increase of $5.0 million from higher net retained fuel due to higher natural gas prices and natural gas volumes retained; and

•	an increase of $3.1 million from additional storage services to meet utility customers’ peak-day demand; offset partially by

•	a decrease of $14.3 million due to lower storage revenues from lower contracted firm capacity.

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•	ONE Gas issued senior notes totaling $1.2 billion, generating net proceeds of approximately $1.19 billion;

•	we received a cash distribution of approximately $1.13 billion from the proceeds of the ONE Gas senior notes offering;

•	we repaid all commercial paper outstanding, which totaled approximately $600.5 million;

•	we paid $150.0 million to retire $152.5 million of senior notes through a tender offer;

•	we called $400 million of senior notes that we repaid in March 2014 for a total of $430.1 million, which included accrued but unpaid interest to the redemption date;

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•	we recorded a loss on extinguishment of $24.8 million in other expense and reclassified losses to interest expense of $7.7 million due to the discontinuance of cash flow hedge treatment for interest-rate swaps related to the debt retirements;

•	we reduced our credit facility to $300 million from $1.2 billion; and

•	we wrote off $2.9 million of previously deferred credit agreement issuance costs to interest expense.

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•	the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices;

•	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 capital intensive nature of our businesses;

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

•	our ability to make cost-saving changes in operations;

•	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;

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

•	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 impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers’ desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities;

•	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 unforeseen changes in interest rates, 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 stock and bond market returns;

•	our indebtedness 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 the credit ratings of ONEOK and ONEOK Partners;

•	the results of administrative proceedings and litigation, regulatory actions, 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 CFTC;

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

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•	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;

•	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 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 Canadian and United States natural gas and crude oil; and

–	availability of additional storage capacity;

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

•	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 mechanical integrity of facilities operated;

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

•	our ability to control operating costs;

•	acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities;

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

•	the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets;

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

•	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 in the Middle East and elsewhere;

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

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

•	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 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;

•	the impact of potential impairment charges;

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

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

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

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•	a $0.01 per-gallon change in the composite price of NGLs would change 12-month forward net margin by approximately $3.0 million;

•	a $1.00 per-barrel change in the price of crude oil would change 12-month forward net margin by approximately $1.6 million; and

•	a $0.10 per-MMBtu change in the price of natural gas would change 12-month forward net margin by approximately $5.2 million.

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A.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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•	Level 1 - fair value measurements are based on unadjusted quoted prices for identical securities in active markets including NYMEX-settled prices. These balances are comprised predominantly of exchange-traded derivative contracts for natural gas and crude oil.

•	Level 2 - fair value measurements are based on significant observable pricing inputs, such as NYMEX-settled prices for natural gas and crude oil and financial models that utilize implied forward LIBOR yield curves for interest-rate swaps.

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Level 3 - fair value measurements are based on inputs that may include one or more unobservable inputs, including internally developed basis curves that incorporate observable and unobservable market data, NGL price curves from broker quotes, market volatilities derived from the most recent NYMEX close spot prices and forward LIBOR curves, and adjustments for the credit risk of our counterparties. We corroborate the data on which our fair value estimates are based using our market knowledge of recent transactions, analysis of historical correlations and validation with independent broker quotes. These balances categorized as Level 3 are comprised of derivatives for natural gas and NGLs. We do not believe that our Level 3 fair value estimates have a material impact on our results of operations, as the majority of our derivatives are accounted for as hedges for which ineffectiveness is not material.

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•	established by independent, third-party regulators;

•	designed to recover the specific entity’s costs of providing regulated services; and

•	set at levels that will recover our costs when considering the demand and competition for our services.

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E.	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; and

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•	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.

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F.	PROPERTY, PLANT AND EQUIPMENT

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G.	GOODWILL AND INTANGIBLE ASSETS

H.	CREDIT FACILITIES AND SHORT-TERM NOTES PAYABLE

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I.	LONG-TERM DEBT

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J.	EQUITY

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K.	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

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L.	EARNINGS PER SHARE

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M.	SHARE-BASED PAYMENTS

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N.	EMPLOYEE BENEFIT PLANS

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O.	INCOME TAXES

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P.	UNCONSOLIDATED AFFILIATES

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Q.	ONEOK PARTNERS

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•	15 percent of amounts distributed in excess of $0.3025 per unit;

•	25 percent of amounts distributed in excess of $0.3575 per unit; and

•	50 percent of amounts distributed in excess of $0.4675 per unit.

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R.	COMMITMENTS AND CONTINGENCIES

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•	an evaluation on whether hazardous natural gas liquids and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;

•	a review of all natural gas and hazardous natural gas liquids gathering pipeline exemptions;

•	a verification of records for pipelines in class 3 and 4 locations and high-consequence areas to confirm maximum allowable operating pressures; and

•	a requirement to test previously untested pipelines operating above 30 percent yield strength in high-consequence areas.

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S.	SEGMENTS

•	the Natural Gas Gathering and Processing segment gathers and processes natural gas;

•	the Natural Gas Liquids segment gathers, treats, fractionates and transports NGLs and stores, markets and distributes NGL products; and

•	the Natural Gas Pipelines segment operates regulated interstate and intrastate natural gas transmission pipelines and natural gas storage facilities.

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T.	QUARTERLY FINANCIAL DATA (UNAUDITED)

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

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

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

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

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