10-K 1 oks10-k2015.htm OKS 10-K 2015 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2015.
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   1-12202
ONEOK PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware
93-1120873
(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:
Common units
New York Stock Exchange
(Title of each class)
(Name of each exchange on which registered)
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes X No__.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes __  No X.

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 X  No __

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every
Interactive Data File required to be submitted and posted 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 and post such files).  Yes X No __

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.  (Check one)
Large accelerated filer X    Accelerated filer __    Non-accelerated filer __    Smaller reporting company __

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes__ No X.

Aggregate market value of the common units held by non-affiliates based on the closing trade price on June 30, 2015, was $5.7 billion.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
Class
 
Outstanding at February 16, 2016
Common units 
 
212,837,980 units
Class B units  
 
72,988,252 units 
DOCUMENTS INCORPORATED BY REFERENCE: None.



ONEOK PARTNERS, L.P.
2015 ANNUAL REPORT

 
 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

As used in this Annual Report, references to “we,” “our,” “us” or the “Partnership” refer to ONEOK Partners, L.P., its subsidiary, ONEOK Partners Intermediate Limited Partnership, and its subsidiaries, unless the context indicates otherwise.


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GLOSSARY

The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:
AFUDC
Allowance for funds used during construction
Annual Report
Annual Report on Form 10-K for the year ended December 31, 2015
ASU
Accounting Standards Update
Bbl
Barrels, 1 barrel is equivalent to 42 United States gallons
BBtu/d
Billion British thermal units per day
Bcf
Billion cubic feet
Bcf/d
Billion cubic feet per day
CFTC
U.S. Commodity Futures Trading Commission
Clean Air Act
Federal Clean Air Act, as amended
Clean Water Act
Federal Water Pollution Control Act Amendments of 1972, as amended
DOT
United States Department of Transportation
EBITDA
Earnings before interest expense, income taxes, depreciation and amortization
EPA
United States Environmental Protection Agency
Exchange Act
Securities Exchange Act of 1934, as amended
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
GAAP
Accounting principles generally accepted in the United States of America
GHG
Greenhouse gas
Intermediate Partnership
ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary
of ONEOK Partners, L.P.
IRS
Internal Revenue Service
KCC
Kansas Corporation Commission
LIBOR
London Interbank Offered Rate
MBbl
Thousand barrels
MBbl/d
Thousand barrels per day
MDth/d
Thousand dekatherms per day
MMBbl
Million barrels
MMBtu
Million British thermal units
MMcf/d
Million cubic feet per day
Moody’s
Moody’s Investors Service, Inc.
Natural Gas Act
Natural Gas Act of 1938, as amended
Natural Gas Policy Act
Natural Gas Policy Act of 1978, as amended
NGL(s)
Natural gas liquid(s)
NGL products
Marketable natural gas liquid purity products, such as ethane, ethane/propane
mix, propane, iso-butane, normal butane and natural gasoline
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
OCC
Oklahoma Corporation Commission
ONE Gas
ONE Gas, Inc.
ONEOK
ONEOK, Inc.
ONEOK Partners
ONEOK Partners, L.P.
ONEOK Partners GP
ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and the
sole general partner of ONEOK Partners
OPIS
Oil Price Information Service
OSHA
Occupational Safety and Health Administration
Partnership Agreement
Third Amended and Restated Agreement of Limited Partnership of ONEOK
Partners, L.P., as amended
Partnership Credit Agreement
The Partnership’s $2.4 billion amended and restated revolving credit
agreement effective as of January 31, 2014, as amended
PHMSA
United States Department of Transportation Pipeline and Hazardous Materials
Safety Administration
POP
Percent of Proceeds

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Quarterly Report(s)
Quarterly Report(s) on Form 10-Q
Roadrunner
Roadrunner Gas Transmission, LLC
RRC
Railroad Commission of Texas
S&P
Standard & Poor’s Rating Services
SCOOP
South Central Oklahoma Oil Province
SEC
Securities and Exchange Commission
Securities Act
Securities Act of 1933, as amended
Term Loan Agreement
The Partnership’s senior unsecured delayed-draw three-year $1.0 billion term loan agreement dated January 8, 2016
West Texas LPG
West Texas LPG Pipeline Limited Partnership and Mesquite Pipeline
WTI
West Texas Intermediate
WTLPG
West Texas LPG Pipeline Limited Partnership
XBRL
eXtensible Business Reporting Language

The statements in this Annual 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,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” 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 1A, Risk Factors, and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and “Forward-Looking Statements,” in this Annual Report.


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PART I

ITEM 1.    BUSINESS

GENERAL

ONEOK Partners, L.P. is a publicly traded master limited partnership, organized under the laws of the state of Delaware, that was formed in 1993. Our common units are listed on the NYSE under the trading symbol “OKS.” We are one of the largest publicly traded master limited partnerships and a leader in the gathering, processing, storage and transportation of natural gas in the United States. In addition, we own one of the nation’s premier natural gas liquids systems, connecting NGL supply in the Mid-Continent, Permian and Rocky Mountain regions with key market centers. We apply our core capabilities of gathering, processing, fractionating, transporting, storing and marketing natural gas and NGLs through the rebundling of services across the value chains through vertical integration in an effort to provide our customers with premium services at lower costs.

EXECUTIVE SUMMARY

Commodity Price Environment - Due in part to the rapid growth in crude oil and natural gas production in the United States, the global supply of crude oil and natural gas exceeded demand and led to a dramatic fall in commodity prices beginning in the fourth quarter 2014. Lower crude oil and natural gas prices persisted throughout 2015 and are expected to remain low in 2016. The production growth and decline in crude oil prices have also contributed to lower NGL product prices, as well as narrow NGL product price differentials.

WTI crude oil prices declined to an average of approximately $50.00 per barrel in 2015, compared with prices averaging approximately $93.00 per barrel in 2014. NYMEX natural gas prices also declined to an average of approximately $2.60 per MMBtu in 2015, compared with prices averaging approximately $4.30 per MMBtu in 2014. OPIS Conway propane prices averaged less than $0.41 per gallon in 2015, compared with prices averaging more than $1.10 per gallon in 2014. At December 31, 2015, prices for WTI crude oil, NYMEX natural gas and OPIS Conway propane declined to approximately $35.00 per barrel, $2.30 per MMBtu and $0.33 per gallon, respectively, and remained weak into early 2016.

We have mitigated partially our exposure to the current commodity price environment by growing our fee-based business. We have a predominantly fee-based business in our Natural Gas Liquids and Natural Gas Pipelines segments and, historically to a lesser extent, in our Natural Gas Gathering and Processing segment. In 2015, however, our Natural Gas Gathering and Processing segment restructured many POP with fee contracts associated with a significant amount of our gathered volumes to increase the fee-based component and will continue to seek opportunities to similarly restructure additional contracts in 2016. These restructured contracts favorably impacted our 2015 results, and we expect to receive the full benefit of the improved earnings from these contracts in our 2016 financial results. In the fourth quarter 2015, our Natural Gas Gathering and Processing segment’s fee revenues averaged $0.55 per MMBtu, compared with an average of $0.36 per MMBtu in 2014. As a result of these restructured contracts, we expect our Natural Gas Gathering and Processing segment’s fee-based earnings to increase significantly to more than 75 percent in 2016 and our consolidated fee-based earnings to increase to approximately 85 percent in 2016. To further mitigate the impact of lower commodity prices, we have hedged a significant portion of our Natural Gas Gathering and Processing segment’s expected equity volumes for 2016 and 2017. Our Natural Gas Liquids and Natural Gas Pipelines segments continue to provide primarily fee-based services, and many of the contracts in these segments include fixed fee, minimum volume or firm demand charge agreements that provide a minimum level of revenues regardless of commodity prices or volumetric throughput.

The current weakened commodity price environment, resulting from factors beyond our control, is creating challenges for our crude oil and natural gas producer customers and resulted in decreased drilling activity in 2015, compared with 2014. In the Williston Basin, the number of rigs drilling on acreage dedicated to us decreased from approximately 80 rigs in January 2015 to approximately 30 rigs in December 2015. Despite the sustained lower crude oil, natural gas and NGL prices and reduced capital spending by producers, we continue to expect demand for midstream services and infrastructure development to be driven by producers who need to connect production with end-use markets where current infrastructure is insufficient or nonexistent. Our natural gas and NGL volumes increased in 2015, particularly in the Williston Basin, as producers are focusing their drilling in the most productive areas and are using more efficient drilling and completion techniques. We expect this lower commodity price environment to continue in 2016, which will impact our net realized prices for natural gas, NGLs and condensate, as well as our financial results. If the low commodity price environment persists for a prolonged period or prices decline further, volumes across our assets may grow more slowly than in the past or decline.

In the future, we expect commodity prices to recover; however, the timing of this recovery is uncertain. We do not expect commodity prices to return in the near term to the levels experienced in the first half of 2014.

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Supply - Natural gas and NGL supply is affected by producer drilling activity, which is sensitive to commodity prices, operating capacity, access to capital and regulatory control. Crude oil and natural gas price declines have continued since 2014, which has resulted in fewer active drilling rigs within our areas of operations. Although drilling has slowed, many of our customers continue to drill new wells in the most productive areas, and improvements in drilling and completion technology are resulting in higher volumes from the wells that are completed. These new technologies, such as multi-well pads and more efficient drilling rigs, are resulting in lower drilling and completion costs, which are mitigating partially the lower commodity prices for our producer customers. In addition, new wells drilled using horizontal drilling technologies tend to produce volumes at higher initial production rates resulting generally in higher initial decline rates than conventional vertical wells; however, the decline rates flatten out over time. A significant portion of our Williston Basin gathering and processing assets are in the most productive areas, which typically produce at higher initial production rates compared with other areas, have the highest natural gas content and have slower natural gas declines than crude oil. We expect our natural gas gathered and processed volumes in the Williston Basin to continue to grow in 2016, despite expected reductions in producer drilling activity. The significant drilling activity in recent years in the Williston Basin has caused natural gas production to exceed the capacity of existing natural gas gathering and processing infrastructure, which results in the flaring of natural gas (the controlled burning of natural gas at the wellhead) by producers. We expect to capture a substantial amount of natural gas currently being flared by producers due to an additional processing plant and compression projects that were placed in service in late 2015 and projects that are expected to be completed in 2016. Additionally, we expect to benefit from production from new wells on acreage dedicated to us in the Williston Basin that have been drilled previously but have not yet been completed or connected to our system by expanding our natural gas gathering and processing and natural gas liquids gathering infrastructure in the Williston Basin.

Supply growth has resulted in available ethane supplies that are greater than the petrochemical industry’s current demand. As a result, low or unprofitable price differentials between ethane and natural gas have resulted in ethane rejection at most of our and our customers’ natural gas processing plants connected to our natural gas liquids gathering system in the Mid-Continent and Rocky Mountain regions during 2014 and 2015, which reduced natural gas liquids volumes gathered, fractionated, transported and sold across our assets. Through ethane rejection, natural gas processors leave much of the ethane component in the natural gas stream sold at the tailgate of natural gas processing plants. We expect ethane rejection to persist at current levels, which have exceeded 150 MBbl/d on our natural gas liquids system during 2015, until ethylene producers increase their capacity to consume additional ethane feedstock volumes through plant modifications, plant expansions and the completion of announced new world-scale ethylene production projects, which are anticipated to begin coming on line in 2017. Ethane rejection is expected to continue to have a significant impact on our financial results into 2017.

Beginning in June 2015, our Natural Gas Gathering and Processing segment reduced its level of ethane rejection in the Williston Basin to alleviate downstream NGL product specification issues, which offsets partially the financial impact of ethane rejection. We expect this decreased ethane rejection to continue throughout 2016. In addition, our Natural Gas Liquids segment’s integrated assets enable us to mitigate partially the impact of ethane rejection through minimum volume commitments, contract modifications that vary fees for ethane and other NGL products, and our ability to utilize the transportation capacity made available due to ethane rejection to capture additional NGL location price differentials, when they exist, in our optimization activities. See additional discussion in the “Financial Results and Operating Information” section of Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Growth Projects - In 2015, crude oil and natural gas producers continued to drill for crude oil and NGL-rich natural gas in many regions where we have operations, including in the Bakken Shale and Three Forks formations in the Williston Basin; in the Cana-Woodford Shale, Woodford Shale, Springer Shale, Stack and SCOOP areas in the Mid-Continent region; and in the Permian Basin. In response to this continued production of crude oil, natural gas and NGLs, and higher demand for NGL products from the petrochemical industry, we have completed growth projects and acquisitions in these regions. In addition, our current projects are expected to expand our natural gas gathering and processing and natural gas liquids gathering infrastructure in the Williston Basin to capture natural gas currently being flared by producers. Through our Roadrunner joint venture, we are constructing a pipeline to transport natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas. The Roadrunner pipeline will connect with our existing natural gas pipeline and storage infrastructure in Texas and, together with our ONEOK WesTex Transmission (WesTex) intrastate natural gas pipeline system expansion project, is expected to create a platform for future opportunities to deliver natural gas supply to Mexico. The execution of these capital investments aligns with our strategy to generate consistent growth and sustainable earnings. Our contractual commitments from crude oil and natural gas producers, natural gas processors and electric generators are expected to provide incremental cash flows and long-term fee-based earnings.

While reduced crude oil and natural gas producer drilling activity is slowing supply growth, we expect to complete our previously announced projects to meet crude oil and natural gas producers’ demands for our gathering, processing, fractionation

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and transportation services. We have suspended capital expenditures for certain natural gas processing plants and related infrastructure to align with the needs of our customers. We could resume our suspended capital-growth projects when market conditions improve and our customers’ needs change. In 2016, we expect lower capital spending, compared with spending levels from 2013 through 2015, due to the current commodity price environment and our alignment of capital-growth projects with the needs of our customers. If the current commodity price environment persists for a prolonged period, it may further impact the timing or demand for additional infrastructure projects or growth opportunities in the future.

Impairment Charges - In the fourth quarter 2015, we recorded $264.3 million of noncash impairment charges, primarily related to our long-lived assets and equity investments in the dry natural gas area of the Powder River Basin.

Cash Distributions - Our structure as a master limited partnership requires us to pay out all of our available cash, as defined in our Partnership Agreement, in distributions to our unitholders. During 2015, we paid cash distributions of $3.16 per unit, an increase of approximately 5 percent over the $3.01 per unit paid during 2014. In January 2016, our general partner declared a cash distribution of $0.79 per unit ($3.16 per unit on an annualized basis) for the fourth quarter 2015.

Liquidity - We rely primarily on operating cash flows, commercial paper, bank credit facilities, debt issuances and the issuance of common units for our liquidity and capital resources requirements. As of December 31, 2015, we had $5.1 million of cash on hand and available capacity under our Partnership Credit Agreement of approximately $1.8 billion. In addition, in January 2016, we entered into the $1.0 billion senior unsecured Term Loan Agreement with a syndicate of banks that matures in January 2019. Proceeds from the Term Loan Agreement effectively refinance our 2016 debt maturities.

The significant decline in commodity prices has increased the cost of debt and equity financing for us and others in our industry. While lower commodity prices and industry uncertainty may result in increased financing costs, we believe we have secured sufficient access to the financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures through 2016 and well into 2017.

In the first quarter 2015, we increased the capacity of our Partnership Credit Agreement to an aggregate of $2.4 billion from $1.7 billion. The facility is available to provide liquidity for working capital, capital expenditures and other general partnership purposes. We also increased the size of our commercial paper program to $2.4 billion from $1.7 billion during the first quarter 2015. At December 31, 2015, we had $246.3 million of commercial paper outstanding, $14.0 million of letters of credit issued and $300 million of borrowings outstanding under our Partnership Credit Agreement.

See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, for more information on our growth projects, results of operations, liquidity and capital resources.

BUSINESS STRATEGY

Our primary business strategy is to increase distributable cash flow per unit through consistent and sustainable earnings growth while focusing on safe, reliable, environmentally responsible and legally compliant operations for our customers, employees, contractors and the public through the following:
Operate in a safe, reliable and environmentally responsible manner - 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;
Generate consistent growth and sustainable earnings - we have a predominantly fee-based business in our Natural Gas Liquids and Natural Gas Pipelines segments and have significantly increased the fee component in our Natural Gas Gathering and Processing segment’s contracts. We are investing in growth projects to meet the needs of crude oil and natural gas producers. Through our Roadrunner joint venture, we are also investing in natural gas pipeline infrastructure from West Texas to the Mexican border that is expected to provide markets in Mexico access to upstream supply basins. When completed, our capital projects are anticipated to provide additional fee-based earnings and cash flows;
Manage our balance sheet and maintain investment-grade credit ratings - even under challenging market conditions, our balance sheet remains strong. We ended 2015 with approximately $1.8 billion of credit available under the Partnership Credit Agreement, and in January 2016, we entered into the $1.0 billion Term Loan Agreement that effectively refinances our 2016 debt maturities. We 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

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focus on employee development efforts with our current employees and monitor our benefits and compensation package to remain competitive.

NARRATIVE DESCRIPTION OF BUSINESS

We report operations in the following business segments:
Natural Gas Gathering and Processing;
Natural Gas Liquids; and
Natural Gas Pipelines.

Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment provides nondiscretionary services to contracted producers in North Dakota, Montana, Wyoming, Kansas and Oklahoma. We provide exploration and production companies with gathering and processing services that allow them to move their raw (unprocessed) natural gas to market. Raw natural gas is gathered, compressed and transported through pipelines to our processing facilities. In order for the raw natural gas to be accepted by the downstream market, it must have contaminants, such as water, nitrogen and carbon dioxide, removed as well as NGLs separated for further processing. Processed natural gas, usually referred to as residue natural gas, is then recompressed and delivered to natural gas pipelines and end users. The separated NGLs are in a mixed, unfractionated form and are sold and delivered through natural gas liquids pipelines to fractionation facilities for further separation.

Rocky Mountain region - The Williston Basin is located in portions of North Dakota and Montana, including the oil-producing, NGL-rich Bakken Shale and Three Forks Formation, and is our most active region with continued volume growth and additional gathering and processing infrastructure needs. Our growth projects are expected to increase our gathering and processing capacity and allow us to capture natural gas from new wells being drilled, wells that have been drilled but have not yet been completed, and natural gas currently being flared by producers. The significant Williston Basin drilling activity in recent years has caused natural gas production to exceed the capacity of existing natural gas gathering and processing infrastructure, which results in the flaring of natural gas by producers. See further discussion of growth projects in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, including expected completion dates.

The Powder River Basin is located in Wyoming. This region includes the NGL-rich Frontier, Turner Sussex and Niobrara Shale where our Sage Creek system provides gathering and processing services to customers in the southeast portion of Wyoming.

Mid-Continent region - Our Mid-Continent region is located in Western Oklahoma, which includes the NGL-rich Cana-Woodford Shale, Stack, SCOOP, Woodford Shale, Springer Shale and the Mississippian Lime Formation; and Southwest Kansas, which includes the Hugoton Basin, Central Kansas Uplift Basin and the Mississippian Lime Formation. The Mid-Continent region includes active drilling in the Cana-Woodford Shale, Woodford Shale, Springer Shale, Stack and SCOOP areas in Oklahoma as well as mature areas with volumetric declines.

Revenues - Revenues for this segment are derived primarily from the following types of contracts:
POP with fee-based components - Under this type of contract, we charge fees for gathering, treating, compressing and processing the producer’s natural gas and retain a percentage of the proceeds from the sale of residue natural gas, condensate and/or NGLs. This type of contract represented approximately 90 percent and 87 percent of contracted volumes in this segment for 2015 and 2014, respectively. There are a variety of factors that directly affect our POP with fee revenues, including:
the price of natural gas, crude oil and NGLs;
the percentage of NGL, condensate and residue natural gas sales proceeds retained by us that we receive as part of the compensation for the services we provide;
the composition of the natural gas and NGLs produced;
the fees we charge for our services;
the volume produced; and
the costs incurred to provide our services.
Over time as our contracts are renewed or restructured, we have generally increased the fee components and reduced the percent of proceeds retained from the sale of the commodities. As a result, our mix of commodity and fee-based earnings continue to change as volumes naturally decline on older contracts where we retain a higher percent of proceeds and volumes increase on contracts with higher fee components. Additionally, under certain POP with fee

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contracts our fee revenues may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds.
Fee-only - Under this type of contract, we are paid a fee for the services we provide, based on volumes gathered, processed, treated and/or compressed. Our fee-only contracts represented approximately 10 percent and 13 percent of contracted volumes in this segment for 2015 and 2014, respectively.

Our gathering and processing agreements have terms ranging from month to month to life of lease. Generally, our gathering and processing agreements are long-term agreements, typically five to 10 years. We have restructured many of our contracts to significantly increase our fee-based earnings and will continue to seek opportunities to similarly restructure additional contracts in 2016. As a result of these restructured contracts, we expect our Natural Gas Gathering and Processing segment’s fee-based earnings to increase significantly and to favorably impact our 2016 results. In the fourth quarter 2015, our Natural Gas Gathering and Processing segment’s fee rates averaged $0.55 per MMBtu, compared with an average of $0.36 per MMBtu in 2014. Our NGLs, natural gas and crude oil commodity price sensitivity in this segment is expected to decrease in 2016 as a result of these restructured contracts. Additionally, we use commodity derivative instruments and physical-forward contracts to reduce our near-term sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for our share of volumes under POP with fee contracts.

Unconsolidated Affiliates - Our Natural Gas Gathering and Processing segment includes the following unconsolidated affiliates:
49 percent ownership in Bighorn Gas Gathering, which operates a coal-bed methane gathering system in the Powder River Basin;
37 percent ownership in Fort Union Gas Gathering, which gathers coal-bed methane produced in the Powder River Basin and delivers it to the interstate pipeline system;
35 percent 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 percent ownership interest in Venice Energy Services Co., a natural gas processing facility near Venice, Louisiana.

See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of our unconsolidated affiliates.

Market Conditions and Seasonality - Supply - Rocky Mountain region - In the Williston Basin, natural gas volumes continued to grow in 2015 as new well connections to our system from drilling completions increased, driven primarily by producer development of Bakken Shale crude oil wells, which also produce associated natural gas containing significant quantities of NGLs. We expect a reduction in well connections in 2016, compared with 2015, due to continued low commodity prices and reduced drilling and completion activity. Volumes are expected to increase in the Williston Basin due to the following:
the opportunity to capture additional natural gas currently being flared by producers with additional natural gas compression and processing capacity on our systems due to projects placed in service in late 2015 and projects that are expected to be completed in 2016;
the connection of wells that have been drilled but not yet completed or connected to our systems;
producers focusing their drilling in the most productive areas, in which we have significant gathering and processing assets, which typically produce at higher initial production rates compared with other areas, have the highest natural gas content and have slower natural gas declines than crude oil;
the use by producers of more efficient drilling rigs; and
continued improvements in production results by producers due to enhanced completion techniques.

The NGL-rich natural gas from the Niobrara area in the Powder River Basin has experienced a reduction in drilling activity due to the current price environment; however, our long-term volume expectations have not materially changed due to the quality of reserves in these proven formations.

Mid-Continent region - In the Mid-Continent region, we have significant natural gas gathering and processing assets in Oklahoma and Kansas. We expect our average natural gas gathered volumes to grow in 2016 due to continued drilling and completion activity in the Cana-Woodford Shale, Woodford Shale, Springer Shale, Stack and SCOOP areas in Oklahoma, offset partially by the natural volume declines from existing wells that supply our natural gas gathering and processing facilities. Producers in the region are targeting their projects by drilling in the most productive areas and minimizing their costs by taking advantage of efficient drilling and completion techniques.


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If the commodity price environment remains low or declines further, volumes in each region may grow more slowly than in the past or decline.

See further discussion of supply in the “Executive Summary” section.

Demand - Demand for gathering and processing services is dependent on production by producers, which is driven by the strength of the economy; natural gas, crude oil and NGL prices; and the demand for each of these products from end users. Our customers are generally crude oil and natural gas producers who have proven reserves or are currently producing gas in areas within our existing infrastructure. Our gathering and processing services are nondiscretionary for these producer customers, as the raw natural gas stream they produce has no marketable value until it is gathered and processed into commodities. Additionally, demand is impacted by the weather.

Rocky Mountain region - Demand for our gathering and processing services in the Williston Basin has remained strong even as crude oil prices have declined. Requirements in North Dakota to reduce producer natural gas flaring have increased the need for our services to capture this natural gas.

Mid-Continent region - Demand for our service remained constant and is linked directly to proven production sources and drilling and completion activities, which are primarily in the Cana Woodford, Springer Shale, Stack and SCOOP areas in Oklahoma. If the commodity price environment remains low or declines further, demand for our services in this region may grow more slowly than in the past or decline.

Commodity Prices - See discussion of commodity prices in the “Executive Summary” section.

Seasonality - Cold temperatures usually increase demand for natural gas, the main heating fuel for homes and businesses. Warm temperatures usually increase demand for natural gas used in gas-fired electric generators for residential and commercial cooling, as well as agriculture related equipment like irrigation pumps and crop dryers. During periods of peak demand for a certain commodity, prices for that product typically increase. However, in the current environment of natural gas oversupply and high storage levels, we do not expect prices to be materially affected by seasonality.

Extreme weather conditions can impact the volumes of natural gas gathered and processed. Freeze-offs are a phenomenon where water produced from natural gas freezes at the wellhead or within the gathering system. This causes a temporary interruption in the flow of natural gas. All of our operations may be affected by other weather conditions that may cause a loss of electricity at our facilities or prevent access to certain locations that affect a producer’s ability to complete wells or our ability to connect those wells to our systems.

Competition - We compete for natural gas supply with major integrated oil companies, independent exploration and production companies that have gathering and processing assets, pipeline companies and their affiliated marketing companies, and other midstream gatherers and processors. The factors that typically affect our ability to compete for natural gas supply are:
quality of services provided;
producer drilling activity;
products retained and/or fees charged under our gathering and processing contracts;
location of our gathering systems relative to those of our competitors;
location of our gathering systems relative to drilling activity;
operating pressures maintained on our gathering systems;
efficiency and reliability of our operations;
delivery capabilities for natural gas and NGLs that exist in each system and plant location; and
cost of capital.

Competition for natural gas gathering and processing services continues to increase as new infrastructure projects are completed to address increased production from shale and other resource areas. In response to these changing industry conditions, we continue to evaluate opportunities to increase earnings and cash flows, and reduce risk by:
improving natural gas processing efficiency;
reducing operating costs;
consolidating assets;
decreasing commodity price exposure; and
restructuring low-margin contracts.


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Customers - Our Natural Gas Gathering and Processing segment provides nondiscretionary services to crude oil and natural gas producers that include the gathering and processing of natural gas produced from crude oil and natural gas wells. Our customers include both large integrated and independent exploration and production companies. We are not typically exposed to material credit risk with producer customers under POP with fee contracts as we receive proceeds from the sale of commodities and remit a portion of those proceeds back to the crude oil and natural gas producers. In 2015, 99 percent of the downstream commodity sales in our Natural Gas Gathering and Processing segment were made to investment-grade customers, as rated by S&P or Moody’s, or our comparable internal ratings, or secured by letters of credit or other collateral.

Government Regulation - The FERC traditionally has maintained that a natural gas processing plant is not a facility for the transportation or sale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act. Although the FERC has made no specific declaration as to the jurisdictional status of our natural gas processing operations or facilities, our natural gas processing plants are primarily involved in extracting NGLs and, therefore, are exempt from FERC jurisdiction. The Natural Gas Act also exempts natural gas gathering facilities from the jurisdiction of the FERC. We believe our natural gas gathering facilities and operations meet the criteria used by the FERC for nonjurisdictional natural gas gathering facility status. Interstate transmission facilities remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities, either interstate or intrastate, on a fact-specific basis. We transport residue natural gas from our natural gas processing plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act. Oklahoma, Kansas, Wyoming, Montana and North Dakota also have statutes regulating, to varying degrees, the gathering of natural gas in those states. In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.

Rocky Mountain region - In July 2014, the North Dakota Industrial Commission (NDIC) approved a policy designed to limit natural gas flaring at existing and future crude oil wells in the Williston Basin. The policy establishes crude oil production limits that will take effect if a producer fails to meet requirements to capture natural gas at the wellhead. We continue to participate actively on the North Dakota Petroleum Council’s Flaring Task Force, which provides recommendations to the NDIC on policies and targets. In 2015, the NDIC passed updated natural gas capture percentages and associated timelines. None of these changes are expected to have a material impact on available production. We are constructing additional natural gas gathering pipelines, processing plants and natural gas liquids pipeline capacity that are expected to help alleviate capacity constraints. As a result, we expect our natural gas gathered and processed volumes in the Williston Basin to continue to grow in 2016, despite expected reductions in producer drilling activity, as we capture natural gas currently being flared by producers and natural gas produced with new drilling focused in the most productive areas.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

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 where we provide nondiscretionary 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 natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, New Mexico, Montana, North Dakota, Wyoming and Colorado, and terminal and storage facilities in Missouri, Nebraska, Iowa and Illinois. We also own FERC-regulated natural gas liquids distribution and refined petroleum products pipelines in Kansas, Missouri, Nebraska, Iowa, Illinois and Indiana that connect our Mid-Continent assets with Midwest markets, including Chicago, Illinois. The majority of the pipeline-connected natural gas processing plants in Oklahoma, Kansas and the Texas Panhandle, which extract unfractionated NGLs from unprocessed natural gas, are connected to our gathering systems. We own and operate truck- and rail-loading and -unloading facilities connected to our natural gas liquids fractionation and pipeline assets. In November 2014, we began transporting unfractionated NGLs from natural gas processing plants in the Permian Basin after completion of the West Texas LPG acquisition.

Most natural gas produced at the wellhead contains a mixture of NGL components, such as ethane, propane, iso-butane, normal butane and natural gasoline. The NGLs that are separated from the natural gas stream at natural gas processing plants remain in a mixed, unfractionated form until they are gathered, primarily by pipeline, and delivered to fractionators where the NGLs are separated into NGL products. These NGL products are then stored or distributed to our customers, such as petrochemical manufacturers, heating fuel users, ethanol producers, refineries, exporters and propane distributors.


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Revenues for our Natural Gas Liquids segment are derived primarily from nondiscretionary fee-based services that we provide to our customers and from the physical optimization of our assets. Our fee-based services have increased due primarily to new supply connections; expansion of existing connections; the completion of capital projects, including our Bakken NGL Pipeline and Sterling III Pipeline; the West Texas LPG acquisition; and expansion of our NGL fractionation capacity, including the completion of our MB-2 and MB-3 fractionators. Our sources of earnings are categorized as exchange services, transportation and storage services, optimization and marketing and isomerization, which are defined as follows:
Our exchange-services activities utilize our assets to gather, fractionate and/or treat unfractionated NGLs, 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. Our exchange services activities are primarily fee-based.
Our transportation and storage services transport unfractionated NGLs, NGL products and refined petroleum products, primarily under FERC-regulated tariffs. Tariffs specify the maximum rates we charge our customers and the general terms and conditions for NGL 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.
Our optimization and marketing activities utilize our assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials. We primarily transport NGL products between Conway, Kansas, and Mont Belvieu, Texas, to capture the location price differentials between the two market centers. Our natural gas liquids storage facilities also are utilized 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.

Excess NGL supply continues to result in narrow NGL location price differentials between the Mid-Continent and Gulf Coast market centers. We expect these narrow price differentials to persist as NGL production continues to increase and new fractionators and pipelines from various NGL-rich shale areas throughout the country, including our growth projects, have alleviated historical constraints affecting NGL prices and location price differentials between the Conway, Kansas, and Mont Belvieu, Texas, market centers.

Unconsolidated Affiliates - Our Natural Gas Liquids segment includes the following unconsolidated affiliates:
50 percent ownership interest in Overland Pass Pipeline Company, which operates an interstate natural gas liquids pipeline system extending approximately 760 miles, originating in Wyoming and Colorado and terminating in Kansas;
50 percent ownership interest in Chisholm Pipeline Company, which operates an interstate natural gas liquids pipeline system extending approximately 185 miles from origin points in Oklahoma and terminating in Kansas; and
50 percent ownership interest in Heartland Pipeline Company, which operates a terminal and pipeline system that transports refined petroleum products in Kansas, Nebraska and Iowa.

See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.

Market Conditions and Seasonality - Supply - The unfractionated NGLs that we gather and transport originate primarily from natural gas processing plants connected to our gathering systems in Oklahoma, Kansas, Texas, New Mexico and the Rocky Mountain region. Our fractionation operations receive NGLs from a variety of processors and pipelines, including our affiliates, located in these regions. Supply for our Natural Gas Liquids segment depends on crude oil and natural gas drilling and production activities by producers, the decline rate of existing production, natural gas processing plant economics and capabilities, and the NGL content of the natural gas that is produced and processed in the areas in which we operate.

See additional discussion of supply in the “Executive Summary” section.

Demand - Demand for NGLs and the ability of natural gas processors to successfully and economically sustain their operations affect the volume of unfractionated NGLs produced by natural gas processing plants, thereby affecting the demand for NGL gathering, fractionation and distribution services. Natural gas and propane are subject to weather-related seasonal demand. Other NGL products are affected by economic conditions and the demand associated with the various industries that utilize the commodity, such as butanes and natural gasoline used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil. Ethane, propane, normal butane and natural gasoline are used by the petrochemical industry to produce chemical products, such as plastic, rubber and synthetic fibers. Several petrochemical companies are constructing new plants, plant expansions, additions or enhancements that improve the light-NGL feed capability of their facilities due primarily to the increased supply and attractive price of ethane, compared with crude oil-based alternatives, as a petrochemical feedstock in the United States. The demand is expected to increase significantly beginning in 2017 when many of the new

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petrochemical plants and plant modifications are expected to be completed. We do not expect the recent decline in crude oil, natural gas and natural gas liquids prices to impact adversely the construction of new petrochemical plants or plant modifications in the Gulf Coast region. In addition, we expect increased international demand for ethane, propane and butane to provide opportunities to increase fee-based earnings in our exchange and storage services and marketing activities.

Commodity Prices - Our Natural Gas Liquids segment provides primarily fee-based services. However, we are exposed to market risk associated with changes in the price of NGLs; the location differential between the Mid-Continent, Chicago, Illinois, and Gulf Coast regions; and the relative price differential between natural gas, NGLs and individual NGL products, which affect our NGL purchases and sales, and our exchange, storage, transportation, optimization and marketing financial results. Since 2013, supply growth from the development of NGL-rich areas and increased capacity available on pipelines that connect the Mid-Continent and Gulf Coast market centers resulted in NGL price differentials remaining narrow between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas. NGL storage revenue may be affected by price volatility and forward pricing of NGL physical contracts versus the price of NGLs on the spot market.

See additional discussion of commodity prices in the “Executive Summary” section.

Seasonality - Our natural gas liquids fractionation and pipeline operations typically experience some seasonal variation. Some NGL products stored and transported through our assets are subject to weather-related seasonal demand, such as propane, which can be used to heat homes during the winter heating season and for agricultural purposes such as crop drying in the fall. Demand for butanes and natural gasoline, which are primarily used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil, may also be subject to some variability during seasonal periods when certain government restrictions on motor fuel blending products change. The ability of natural gas processors to produce NGLs also is affected by weather. Extreme weather conditions can impact the volumes of natural gas gathered and processed and NGL volumes gathered, transported and fractionated. Freeze-offs are a phenomenon where water produced from natural gas freezes at the wellhead or within the gathering system. This causes a temporary interruption in the flow of natural gas and, consequently, NGLs. Conversely, in periods of hot weather, the natural gas processing plants become less efficient in NGL recovery, and thus NGL recovery during the summer typically decreases.

Competition - Our Natural Gas Liquids segment competes with other fractionators; intrastate and interstate pipeline companies; storage providers and gatherers and transporters for NGL supply in the Rocky Mountain, Permian, Mid-Continent and Gulf Coast regions. The factors that typically affect our ability to compete for NGL supply are:
quality of services provided;
producer drilling activity;
the petrochemical industry’s level of capacity utilization and feedstock requirements;
fees charged under our contracts;
current and forward NGL prices;
location of our gathering systems relative to our competitors;
location of our gathering systems relative to drilling activity;
proximity to NGL supply areas and markets;
efficiency and reliability of our operations;
receipt and delivery capabilities that exist in each pipeline system, plant, fractionator and storage location; and
cost of capital.

We have responded to these factors by making capital investments to access new supplies; increasing gathering, fractionation and distribution capacity; increasing storage, withdrawal and injection capabilities; and reducing operating costs so that we may compete effectively. Our competitors are constructing or have completed new natural gas liquids pipeline and fractionation projects to address the growing NGL supply and petrochemical demand. As our growth projects and those of our competitors have alleviated constraints between the Mid-Continent and Gulf Coast NGL market centers, we expect the narrow location price differentials between the two locations to continue. In addition, new natural gas liquids pipeline projects constructed by third parties are expected to bring incremental NGL supply from the Rocky Mountain, Marcellus and Utica basins to the Gulf Coast market center that may affect NGL prices, as well as compete with or displace NGL supply volumes from the Mid-Continent and Rocky Mountain regions where our assets are located. We believe our natural gas liquids fractionation, pipelines and storage assets are located strategically, connecting diverse supply areas to market centers.

Customers - Our Natural Gas Liquids segment’s customers are primarily NGL and natural gas gathering and processing companies; major and independent crude oil and natural gas production companies; propane distributors; ethanol producers; and petrochemical, refining and NGL marketing companies. We earn fee revenue from NGL and natural gas gathering and

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processing customers and natural gas liquids pipeline transportation customers. We are not typically exposed to material credit risk on the majority of our exchange services fee revenues, as we purchase NGLs from our gathering and processing customers and deduct our fee from the amounts we remit. We also earn commodity sales revenue from the downstream sales of NGL products. In 2015, more than 80 percent of our commodity sales were made to investment-grade customers, as rated by S&P or Moody’s, or our comparable internal ratings, or secured by letters of credit or other collateral. In addition, the majority of our Natural Gas Liquids segment’s pipeline tariffs provide us the ability to require security from shippers.

Government Regulation - The operations and revenues of our natural gas liquids pipelines are regulated by various state and federal government agencies. Our interstate natural gas liquids pipelines are regulated by the FERC, which has authority over the terms and conditions of service; rates, including depreciation and amortization policies; and initiation of service. In Oklahoma, Kansas and Texas, certain aspects of our intrastate natural gas liquids pipelines that provide common carrier service are subject to the jurisdiction of the OCC, KCC and RRC, respectively.

PHMSA has asserted jurisdiction over certain portions of our fractionation facilities in Bushton, Kansas, that it believes are subject to its jurisdiction. We have objected to the scope of PHMSA’s jurisdiction and are seeking resolution of this matter. We do not anticipate that the cost of compliance will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment provides transportation and storage services to end users through its wholly owned assets and its 50 percent ownership in Northern Border Pipeline. Our 50-50 Roadrunner joint venture currently is under construction, with Phase I expected to be completed in the first quarter 2016.

Interstate Pipelines - Our interstate pipelines are regulated by the FERC and are located in North Dakota, Minnesota, Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New Mexico. Our interstate pipeline companies include:
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 at the Chicago Hub near Joliet, Illinois;
Viking Gas Transmission, which is a bidirectional system that interconnects with a TransCanada Corporation 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 interconnections with several pipelines in Oklahoma, Texas and New Mexico.

Intrastate Pipelines - Our intrastate natural gas pipeline assets in Oklahoma transport natural gas through the state and have access to the major natural gas producing formations, including the Cana-Woodford Shale, Woodford Shale, Springer Shale, Granite Wash, Stack, SCOOP and Mississippian Lime. Our intrastate natural gas pipeline assets in Oklahoma serve end-use markets, such as local distribution companies and power generation companies. In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing formations in the Texas Panhandle, including the Granite Wash formation and Delaware and Cline producing formations in the Permian Basin. The pipelines are capable of transporting natural gas throughout the western portion of Texas, including the Waha Hub where other pipelines may be accessed for transportation to western markets, exports to Mexico, the Houston Ship Channel market to the east and the Mid-Continent market to the north. We also have access to the natural gas producing formations in south central Kansas. Through our Roadrunner joint venture, we are constructing a pipeline to transport natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas. The Roadrunner pipeline will connect with our existing natural gas pipeline and storage infrastructure in Texas and, together with our WesTex intrastate natural gas pipeline expansion project, is expected to create a platform for future opportunities to deliver natural gas supply to Mexico.


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Transportation Rates - Our transportation contracts for our regulated natural gas activities are based upon rates stated in the respective tariffs. The tariffs provide both the general terms and conditions for the facilities and the maximum allowed rates customers can be charged by type of service, which may be discounted to meet competition if necessary. The rates are established at FERC or the appropriate state jurisdictional agencies. Our revenues are primarily fee based from the following types of services:
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. In addition, we may retain a percentage of fuel in-kind based on the volumes of natural gas transported. 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. Customers typically are assessed fees, such as a commodity charge, and we may retain a specified volume of natural gas in-kind based on their actual usage.

Storage - We own natural gas storage facilities located in Texas and Oklahoma that are connected to our intrastate natural gas pipelines. We also have underground natural gas storage facilities in Kansas. In Texas and Kansas, natural gas storage operations may be regulated by the state in which the facility operates and by the FERC for certain types of services. In Oklahoma, natural gas storage operations are not subject to rate regulation by the state and have market-based rate authority from the FERC for certain types of services.

Storage Rates - Our revenues are primarily fee based from the following types of services:
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 service offered to customers providing the ability to park (inject) or loan (withdraw) natural gas into or out of our storage, typically for monthly terms. Customers reserve the right to park or loan natural gas based on a specified quantity, including injection and withdrawal rights when capacity is available.

Unconsolidated Affiliates - Our Natural Gas Pipelines segment includes the following unconsolidated affiliates:
50 percent 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, to a terminus near North Hayden, Indiana.
50 percent interest in Roadrunner, which is currently under construction, with Phase I expected to be completed in the first quarter 2016. The Roadrunner pipeline will transport natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas.

See Note M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.

Market Conditions and Seasonality - Supply - The development of natural gas produced from shale resource areas has continued to increase available supply across North America and has caused location and seasonal price differentials to narrow in the regions where we operate.

Interstate - Guardian Pipeline, Midwestern Gas Transmission and Viking Gas Transmission access supply from the major producing regions of the Mid-Continent, Rocky Mountains, Canada, Gulf Coast and the Northeast. The current supply of natural gas for Northern Border Pipeline is primarily sourced from Canada; however, as the Williston Basin supply area continues to develop, more natural gas supply from this area is expected to be transported on Northern Border Pipeline to markets near Chicago. In addition, supply volumes from nontraditional natural gas production areas, such as the Marcellus and Utica shale area in the Northeast, may compete with and displace volumes from the Mid-Continent, Rocky Mountain and Canadian supply sources in our markets. Factors that may impact the supply of Canadian natural gas transported by our pipelines are primarily the availability of United States supply, Canadian natural gas available for export, Canadian storage capacity, government regulation and demand for Canadian natural gas in Canada and United States consumer markets.

Intrastate and Storage - Our intrastate pipelines and storage assets may be impacted by the pace of drilling activity by crude oil and natural gas producers and the decline rate of existing production in the major natural gas production areas in the Mid-

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Continent region, which includes the Cana-Woodford Shale, Granite Wash and Mississippian Lime areas, Hugoton Basin and Central Kansas Uplift Basin.

Demand - Demand for our services is related directly to our access to supply and the demand for natural gas by the markets that our natural gas pipelines and storage facilities serve. Demand is also affected by weather, the economy, natural gas price volatility and regulatory changes.
Weather - The effect of weather on our natural gas pipelines operations is discussed below under “Seasonality.”
Economy - The strength of the economy directly impacts manufacturing and industrial companies that consume natural gas.
Price volatility - Commodity price volatility can influence producers’ decisions related to the production of natural gas. Our pipeline customers, primarily natural gas and electric utilities, require natural gas to operate their businesses and generally are not impacted by location price differentials. However, narrower location price differentials may impact demand for our services from natural gas marketers as discussed below under “Commodity Prices.”
Regulatory - Demand for our services is also affected as coal-fired electric generators are retired and replaced with alternative power generation fuels such as natural gas. EPA regulations on emissions from coal-fired electric-generation plants, including the Maximum Achievable Control Technology Standards and the Mercury and Air Toxics Standards, have increased the demand for natural gas as a fuel for electric generation, as well as related transportation and storage services. The demand for natural gas and related transportation and storage services is expected to increase over the next several years as these regulations continue to be implemented.

Commodity Prices - As a result of excess supplies of natural gas and the addition of natural gas infrastructure, the natural gas location and seasonal price differentials have remained narrow across the regions where we operate. Although our revenues are primarily fee based, commodity prices can affect our results of operations.
Transportation - We are exposed to market risk through interruptible contracts or when existing firm contracts expire and are subject to renegotiation with customers that have competitive alternatives.
Storage - Natural gas storage revenue is impacted by the differential between forward pricing of natural gas physical contracts and the price of natural gas on the spot market.
Fuel - Our fuel costs and the value of the retained fuel in-kind received for our services also are impacted by changes in the price of natural gas.

Seasonality - Demand for natural gas is seasonal. Weather conditions throughout North America may significantly impact regional natural gas supply and demand. High temperatures may increase demand for gas-fired electric generation needed to meet the electricity demand required to cool residential and commercial properties. Cold temperatures may lead to greater demand for our transportation services due to increased demand for natural gas to heat residential and commercial properties. Low precipitation levels may impact the demand for natural gas that is used to fuel irrigation activity in the Mid-Continent region.

To the extent that pipeline capacity is contracted under firm-service transportation agreements, revenue, which is generated primarily from fixed fee charges, is not significantly impacted by seasonal throughput variations. However, when transportation agreements expire, seasonal demand may affect the value of firm-service transportation capacity.

Natural gas storage is necessary to balance the relatively steady natural gas supply with the seasonal demand of residential, commercial and electric-generation users. The majority of our storage capacity is contracted under firm-service agreements; however, we retain a portion of our storage capacity for operational purposes, and the remaining capacity is used to provide park-and-loan services.

Competition - Our natural gas pipelines and storage facilities compete directly with other intrastate and interstate pipeline companies and other storage facilities. Competition among pipelines and natural gas storage facilities is based primarily on fees for services, quality and reliability of services provided, current and forward natural gas prices, proximity to natural gas supply areas and markets, and access to capital. Competition for natural gas transportation services continues to increase as new infrastructure projects are completed and the FERC and state regulatory bodies continue to encourage more competition in the natural gas markets. Regulatory bodies also are encouraging the use of natural gas for electric generation that has traditionally been fueled by coal. The cost of coal and the associated rail transportation continues to compete with natural gas for this market; however, the clean-burning aspects of natural gas and abundance of supply make it an economically competitive and environmentally advantaged alternative. We believe that our pipelines and storage assets compete effectively due to their strategic locations connecting supply areas to market centers and other pipelines.


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Customers - Our natural gas pipeline assets primarily serve local natural gas distribution companies, electric-generation facilities, large industrial companies, municipalities, irrigation customers and marketing companies. Our utility customers generally require our services regardless of commodity prices. In 2015, more than 85 percent of our revenues in this segment were from investment-grade customers, as rated by S&P or Moody’s, or our comparable internal ratings, or secured by letters of credit or other collateral. In addition, the majority of our Natural Gas Pipeline segment’s pipeline tariffs provide us the ability to require security from shippers.

Government Regulation - Interstate - Our interstate natural gas pipelines are regulated under the Natural Gas Act and Natural Gas Policy Act, which give the FERC jurisdiction to regulate virtually all aspects of this business, such as transportation of natural gas, rates and charges for services, construction of new facilities, depreciation and amortization policies, acquisition and disposition of facilities, and the initiation and discontinuation of services.

In November 2012, the FERC initiated a review of Viking Gas Transmission’s rates pursuant to Section 5 of the Natural Gas Act. The parties reached agreement on the terms of a settlement that provides for a 2 percent reduction in transportation rates. The settlement was approved by the FERC in December 2013, and the revised rates became effective January 1, 2014.

In August 2014, Viking Gas Transmission filed a prefiling “Stipulation and Agreement in Resolutions of All Issues Concerning Adjustment in Rates of Viking Gas Transmission Company” (settlement) with the FERC. The settlement was approved on October 1, 2014, and became final on October 31, 2014. Rates under the settlement became effective January 1, 2015.

Intrastate - Our intrastate natural gas pipelines in Oklahoma, Kansas and Texas are regulated by the OCC, KCC and RRC, respectively. While we have flexibility in establishing natural gas transportation rates with customers, there is a maximum rate that we can charge our customers in Oklahoma and Kansas. In Kansas and Texas, natural gas storage may be regulated by the state and by the FERC for certain types of services. In Oklahoma, natural gas storage is not subject to rate regulation by the state, and we have market-based rate authority from the FERC for certain types of services.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

SEGMENT FINANCIAL INFORMATION

Operating Income, Customers and Total Assets - See Note P of the Notes to Consolidated Financial Statements in this Annual Report for disclosure by segment of our operating income and total assets and for a discussion of revenues from external customers.

REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS

Environmental Matters - We are subject to multiple historical preservation, wildlife 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 preservation, 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 and/or interruptions in our operations that could be material to our results of operations. For example, if a leak or spill of hazardous substances or petroleum products occurs from pipelines or facilities that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including response, investigation and cleanup costs, which could affect materially our results of operations and cash flows. 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.

In June 2013, the Executive Office of the President of the United States (the President) issued the President’s Climate Action Plan, which includes, among other things, plans for further regulatory actions to reduce carbon emissions from various sources. In March 2014, the President released the Climate Action Plan - Strategy to Reduce Methane Emissions (Methane Strategy) that lists a number of actions the federal agencies will undertake to continue to reduce above-ground methane emissions from several industries, including the oil and natural gas sectors. The proposed measures outlined in the Methane Strategy include, without limitation, the following: collaboration with the states to encourage emission reductions; standards to minimize natural gas venting and flaring on public lands; policy recommendations for reducing emissions from energy infrastructure to increase the performance of the nation’s energy transmission, storage and distribution systems; and continued efforts by PHMSA to require pipeline operators to take steps to eliminate leaks and prevent accidental methane releases and evaluate the progress of

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states in replacing cast-iron pipelines. The impact of any such regulatory actions on our facilities and operations is unknown. We continue to monitor these developments and the impact they may have on our businesses. Revised or additional statutes or regulations that result in increased compliance costs or additional operating restrictions could have a significant impact on our business, financial position, results of operations and cash flows.

Pipeline Safety - We are subject to PHMSA regulations, including pipeline asset integrity-management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas. In January 2012, The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was signed into law. The law increased maximum penalties for violating federal pipeline safety regulations and directs the DOT and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us. These issues include, but are not limited to, the following:
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.

In October 2015, PHMSA issued a notice of proposed rule-making to its hazardous liquid pipeline safety regulations. Among other things, the proposed regulations would expand the current leak-detection requirements, apply new, more conservative repair criteria and establish timelines for inspecting pipeline facilities potentially affected by an extreme weather event or natural disaster. The proposal would also increase the stringency of integrity management program requirements and set deadlines for the use of internal inspection tools on certain systems. Comments on the proposed rule-making were due by January 2016. The potential capital and operating expenditures related to the referenced legislation and regulations are unknown, but we do not anticipate a material impact to our planned capital, operations and maintenance costs resulting from compliance with the current or pending regulations.

Air and Water Emissions - The Clean Air Act, the Clean Water Act, analogous state laws and/or regulations promulgated thereunder impose restrictions and controls regarding the discharge of pollutants into the air and water in the United States. Under the Clean Air Act, a federally enforceable operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for the removal of pollutants discharged to waters of the United States and remediation of waters affected by such discharge.

Federal, state and regional initiatives to measure and regulate GHG emissions are underway. We monitor all relevant federal and state legislation to assess the potential impact on our operations. The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual GHG emissions reporting from affected facilities and the carbon dioxide emission equivalents for the natural gas delivered by us and the emission equivalents for all NGLs produced by us as if all of these products were combusted, even if they are used otherwise.

Our 2014 total reported emissions were approximately 45.7 million metric tons of carbon dioxide equivalents. This total includes direct emissions from the combustion of fuel in our equipment, such as compressor engines and heaters, as well as carbon dioxide equivalents from natural gas and NGL products delivered to customers and produced as if all such fuel and NGL products were combusted. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In addition, Congress has considered, and may consider in the future, legislation to reduce GHG emissions, including carbon dioxide and methane. Likewise, the EPA may institute additional regulatory rule-making associated with GHG emissions from the oil and natural gas industry. At this time, no rule or legislation has been enacted that assesses any costs, fees or expenses on any of these emissions.

In April 2014, the EPA and the United States Army Corps of Engineers proposed a joint rule-making to redefine the definition of “Waters of the United States” under the Clean Water Act. The final rule was published in June 2015 and became effective on August 28, 2015. Multiple legal actions on the final rule were filed. In October 2015, the Unites States Court of Appeals for the Sixth Circuit entered an order of stay, which is still in effect, and postponed the effect of the final rule nationwide until it decided further proceedings in the case. The final rule is not expected to result in material impacts on our projects, facilities and operations.


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The EPA’s “Triggering and Tailoring Rules” regulate GHG emissions at new or modified facilities that meet certain criteria. Affected facilities are required to review best available control technology (BACT) and conduct air-quality analysis, impact analysis and public reviews with respect to such emissions. At current emission threshold levels, this rule has had a minimal impact on our existing facilities. In addition, in June 2014, the Supreme Court of the United States (Supreme Court), in a case styled, Utility Air Regulatory Group v. EPA, 530 U.S. (2014), held that an industrial facility’s potential to emit GHG emissions alone cannot subject a facility to the permitting requirements for major stationary source provisions of the Clean Air Act. The decision invalidated the EPA’s current Triggering and Tailoring Rule for GHG Prevention of Significant Deterioration (PSD) and Title V requirements as applied to facilities considered major sources only for GHGs (referred to as Step 2 sources). However, the Supreme Court also ruled that to the extent a source pursues a capital project (new construction or expansion of existing facility), which otherwise subjects the source to major source PSD permitting for conventional criteria pollutants, the permitting authorities may impose BACT analysis and emission limits for GHGs from those sources.

In April 2015, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), on remand from the Supreme Court, issued its order following the Supreme Court’s decision in Utility Air Regulatory Group v. EPA. The D.C. Circuit’s order: (1) formally vacated EPA regulations implementing the Tailoring Rule to the extent that they require a stationary source to obtain a PSD or Title V permit based solely on the source’s GHG emissions; and (2) ordered the EPA to consider whether any further revisions to its regulations are appropriate in light of the Supreme Court’s decision. In April 2015, the EPA issued a direct final rule to allow for the rescission of Clean Air Act PSD permits issued by the EPA or delegated state and local permitting authorities under Step 2 of the GHG Tailoring Rule. The direct final rule was to become effective unless adverse comments were received by the EPA. In August 2015, the EPA published the direct final rule to confirm that no adverse comments were received and that the rule was now in effect. We do not expect the direct final rule to have a material impact on our existing operations or design decisions for new project applications.

In July 2011, the EPA issued a proposed rule that would change the air emissions New Source Performance Standards, also known as NSPS, and Maximum Achievable Control Technology requirements applicable to the oil and natural gas industry, including natural gas production, processing, transmission and underground storage sectors. In April 2012, the EPA released the final rule, which includes new NSPS and air toxic standards for a variety of sources within natural gas processing plants, oil and natural gas production facilities and natural gas transmission stations. The rule also regulates emissions from the hydraulic fracturing of wells for the first time. The NSPS final rule became effective in October 2012, but the dates for compliance vary and depend in part upon the type of affected facility and the date of construction, reconstruction or modification.

In September 2015, the EPA published several proposed rule-makings that affect the oil and gas industry. The rule-makings included, but were not limited to, proposed amendments to the NSPS rule. The proposed amendments to the NSPS rule included, in part, the proposed direct regulation of methane emissions for the first time as an individual air pollutant from oil and gas sources, as part of the President’s Methane Strategy. The public comments period on the proposed rule-makings ended on December 4, 2015.

In October 2015, the EPA issued a final rule-making to amend downward the National Ambient Air Quality Standards (NAAQS) for ground level ozone. The final rule requires revised designations of the areas in the various states for classification as in attainment or nonattainment for the new ozone NAAQS. Any areas determined to not attain the ozone NAAQS will implicate more strict air permitting requirements for new or modified sources that emit pollutants that contribute to ground level ozone.

At this time we do not anticipate a material impact to our planned capital, operations and maintenance costs resulting from compliance with the current or pending regulations outlined above. However, the EPA may issue additional responses, amendments and/or policy guidance on the final rules, which could alter our present expectations. Generally, the EPA rule-makings will require expenditures for updated emissions controls, monitoring and record-keeping requirements at affected facilities. We do not expect these expenditures will have a material impact on our results of operations, financial position or cash flows.

CERCLA - The federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also commonly known as Superfund, imposes strict, joint and several liability, without regard to fault or the legality of the original act, on certain classes of “persons” (defined under CERCLA) who caused and/or contributed to the release of a hazardous substance into the environment. These persons include, but are not limited to, the owner or operator of a facility where the release occurred and/or companies that disposed or arranged for the disposal of the hazardous substances found at the facility. Under CERCLA, these persons may be liable for the costs of cleaning up the hazardous substances released into the environment, damages to natural resources and the costs of certain health studies. We do not expect our responsibilities under CERCLA will have a material impact on our results of operations, financial position or cash flows.


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Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released the Chemical Facility Anti-Terrorism Standards in 2007, and the new final rule associated with these regulations was issued in December 2014. We provided information regarding our chemicals via Top-Screens submitted to Homeland Security, and our facilities subsequently were assigned one of four risk-based tiers ranging from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low risk. To date, four of our facilities have been given a Tier 4 rating. Facilities receiving a Tier 4 rating are required to complete Site Security Plans and possible physical security enhancements. We do not expect the Site Security Plans and possible security enhancement costs to have a material impact on our results of operations, financial position or cash flows.

Pipeline Security - The United States Department of Homeland Security’s Transportation Security Administration and the DOT have completed a review and inspection of our “critical facilities” and identified no material security issues. Also, the Transportation Security Administration has released new pipeline security guidelines that include broader definitions for the determination of pipeline “critical facilities.” We have reviewed our pipeline facilities according to the new guideline requirements, and there have been no material changes required to date.

Environmental Footprint - Our environmental and climate change strategy focuses on minimizing the impact of our operations on the environment. These strategies include: (i) developing and maintaining an accurate GHG emissions inventory according to current rules issued by the EPA; (ii) improving the efficiency of our various pipelines, natural gas processing facilities and natural gas liquids fractionation facilities; (iii) following developing technologies for emissions control and the capture of carbon dioxide to keep it from reaching the atmosphere; and (iv) utilizing practices to reduce the loss of methane from our facilities.

We participate in the EPA’s Natural Gas STAR Program to reduce voluntarily methane emissions. We continue to focus on maintaining low rates of lost-and-unaccounted-for methane gas through expanded implementation of best practices to limit the release of natural gas during pipeline and facility maintenance and operations.

EMPLOYEES

We do not employ directly any of the persons responsible for managing, operating or providing us with services related to our day-to-day business affairs. We have a service agreement with ONEOK and ONEOK Partners GP (the Services Agreement) under which our operations and the operations of ONEOK and its affiliates can combine or share certain common services in order to operate more efficiently and cost effectively. Under the Services Agreement, ONEOK provides us an equivalent type and amount of services that it provides to its other affiliates, including those services required to be provided pursuant to our Partnership Agreement. ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement. As of January 31, 2016, we utilized some or all of the services of 2,364 people in addition to the other resources provided by ONEOK and its affiliates.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneokpartners.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, Governance Guidelines, Partnership Agreement and the written charter of our Audit Committee also are available on our website, and we will provide copies of these documents upon request. Our website and any contents thereof are not incorporated by reference into this report.

We also make available on our website the Interactive Data Files required to be submitted and posted pursuant to Rule 405 of Regulation S-T.

ITEM 1A.    RISK FACTORS

Our investors should consider the following risks that could affect us and our business. Although we have tried to identify 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 following discussion of risks and the other information included or incorporated by reference in this Annual Report, including “Forward-Looking Statements,” which are included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.


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RISKS INHERENT IN OUR BUSINESS

We are subject to market volatility and other risks that could limit our access to capital, thereby increasing our costs and affecting adversely our results of operations.

The capital and global credit markets have experienced volatility and disruption in the past. In many cases during these periods, the capital markets have exerted downward pressure on equity values and reduced the credit capacity for certain companies. Much of our business is capital intensive, and our ability to grow is dependent, in part, upon our ability to access capital at rates and on terms we determine to be attractive. Similar or more severe levels of global market disruption and volatility may have an adverse effect on us resulting from, but not limited to, disruption of our access to capital and credit markets, difficulty in obtaining financing necessary to expand facilities or acquire assets, increased financing costs and increasingly restrictive covenants. If we are unable to access capital at competitive rates, our strategy of enhancing the earnings potential of our existing assets, including through capital-growth projects and acquisitions of complementary assets or businesses, may be affected adversely. A number of factors could affect adversely our ability to access capital, including: (i) general economic conditions; (ii) capital market conditions; (iii) market prices for natural gas, NGLs and other hydrocarbons; (iv) the overall health of the energy and related industries; (v) ability to maintain investment-grade credit ratings; (vi) unit price and (vii) capital structure. If our ability to access capital becomes constrained significantly, our interest costs and cost of equity will likely increase and could affect adversely our financial condition and future results of operations.

Increased competition could have a significant adverse financial impact on our business.

The natural gas and natural gas liquids industries are expected to remain highly competitive. The demand for natural gas and NGLs is primarily a function of commodity prices, including prices for alternative energy sources, customer usage rates, weather, economic conditions and service costs. Our ability to compete also depends on a number of other factors, including competition from other companies for our existing customers; the efficiency, quality and reliability of the services we provide; and competition for throughput at our gathering systems, pipelines, processing plants, fractionators and storage facilities.

Our operating results may be affected materially and adversely by unfavorable economic and market conditions.

Economic conditions worldwide have from time to time contributed to slowdowns in the crude oil and natural gas industry, as well as in the specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions may also be affected by uncertain or changing economic conditions within that region. Volatility in commodity prices may have an impact on many of our customers, which, in turn, could have a negative impact on their ability to meet their obligations to us. If global economic and market conditions (including volatility in commodity markets) or economic conditions in the United States or other key markets remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition, results of operations and liquidity.

The volatility of natural gas, crude oil and NGL prices could affect adversely our earnings and cash flows.

A significant portion of our revenues are derived from the sale of commodities that are received as payment for natural gas gathering and processing services, for the transportation and storage of natural gas, and from the purchase and sale of NGLs and NGL products. Commodity prices have been volatile and are likely to continue to be so in the future. The prices we receive for our commodities are subject to wide fluctuations in response to a variety of factors beyond our control, including, but not limited to, the following:
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;

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the effect of worldwide energy-conservation measures; and
the impact of new supplies, new pipelines, processing and fractionation facilities on location price differentials.

These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of commodities and the impact commodity price fluctuations have on our customers and their need for our services, which could have a material adverse effect on our earnings and cash flows. As commodity prices decline, we are paid less for our commodities, thereby reducing our cash flow. In addition, crude oil, natural gas and NGL production could also decline due to lower prices.

If the level of drilling and production in the Mid-Continent, Rocky Mountain, Permian Basin and Gulf Coast regions declines substantially near our assets, our volumes and revenues could decline.

Our gathering and transportation pipeline systems are connected to, and dependent on the level of production from, natural gas and crude oil wells, from which production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and the asset utilization rates at our processing and fractionation plants, we must continually obtain new supplies. Our ability to maintain or expand our businesses depends largely on the level of drilling and production by third parties in the Mid-Continent, Rocky Mountain, Permian Basin and Gulf Coast regions. Our natural gas and NGL supply volumes may be impacted if producers curtail or redirect drilling and production activities. Drilling and production are impacted by factors beyond our control, including:
demand and prices for natural gas, NGLs and crude oil;
producers’ access to capital;
producers’ finding and development 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 our facilities.
Commodity prices have declined substantially and experienced significant volatility. Drilling and production activity levels may vary across our geographic areas; however, a prolonged period of low commodity prices may reduce drilling and production activities across all areas. If we are not able to obtain new supplies to replace the natural decline in volumes from existing wells or because of competition, throughput on our gathering and transportation pipeline systems and the utilization rates of our processing and fractionation facilities would decline, which could have a material adverse effect on our business, results of operations, financial position and cash flows, and our ability to make cash distributions.

We are exposed to the credit risk of our customers or counterparties, and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of loss resulting from nonpayment and/or nonperformance by our customers and counterparties. Our customers or counterparties may experience rapid deterioration of their financial condition as a result of changing market conditions, commodity prices or financial difficulties that could impact their creditworthiness or ability to pay us for our services. We assess the creditworthiness of our customers and counterparties and obtain collateral or contractual terms as we deem appropriate. We cannot, however, predict to what extent our business may be impacted by deteriorating market or financial conditions, including possible declines in our customers’ and counterparties’ creditworthiness. The recent decline in commodity prices has negatively impacted the financial condition of certain customers and counterparties and further declines, a prolonged low commodity price environment, or continued volatility could impact their ability to meet their financial obligations to us. Our customers and counterparties may not perform or adhere to our existing or future contractual arrangements. To the extent our customers and counterparties are in financial distress or commence bankruptcy proceedings, contracts with them may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If we fail to assess adequately the creditworthiness of existing or future customers and counterparties any material nonpayment or nonperformance by our customers and counterparties due to inability or unwillingness to perform or adhere to contractual arrangements could have a material adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our primary market areas are located in the Mid-Continent, Rocky Mountain, Permian Basin and Gulf Coast regions of the U.S. Our revenues are derived primarily from major integrated and independent exploration and production, pipeline, marketing and petrochemical companies. Therefore our customers and counterparties may be similarly affected by changes in economic, regulatory or other factors that may affect our overall credit risk.

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We may not be able to generate sufficient cash from operations to allow us to pay quarterly distributions at current or higher levels after the establishment of cash reserves and payment of fees and expenses, including payments to our affiliates.

The amount of cash we can distribute to our unitholders depends principally upon the cash we generate from our operations, which includes activities with our affiliates. Because the cash we generate from operations will fluctuate from quarter to quarter, we may not be able to maintain future quarterly distributions at the current level. The actual amount of cash that is available to be distributed each quarter will depend on numerous factors, some of which are beyond our control and the control of our general partner. Cash distributions are dependent primarily on cash flow, including cash flow from operations, cash from financial reserves and working capital borrowings, and not solely on profitability, which is affected by noncash items. Therefore, cash distributions might be made during periods when we record losses and might not be made during periods when we record profits. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at our current distribution rate under our cash distribution policy. The amount of cash we can distribute principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
the fees we charge and the income we realize for our services;
the prices of, levels of production of and demand for, natural gas, NGLs and crude oil;
the volume of natural gas we gather, treat, compress, process, transport and sell and the volume of NGLs we process or fractionate and sell;
the relationship between natural gas and NGL prices;
cash settlements of hedging positions;
the level of competition from other midstream energy companies;
the level of our operating and maintenance costs; and
prevailing economic conditions.

In addition, the actual amount of cash available for distribution will depend on other factors, some of which are beyond our control, including:
the level of capital expenditures we make;
the cost of acquisitions;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
restrictions on distributions contained in our debt agreements; and
the amount of cash reserves established by our general partner for the proper conduct of our business.

Cost reimbursements payable to our general partner may be substantial and may reduce our ability to pay quarterly distributions.

Prior to paying quarterly distributions, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our general partner in accordance with the terms of the Services Agreement. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to pay quarterly distributions. Our general partner has sole discretion to determine the amount of these expenses and fees, subject to certain limitations as set forth in the Services Agreement.

Our businesses are subject to market and credit risks.

We are exposed to market and credit risks in all of our operations. To reduce the impact of commodity price fluctuations, we may use derivative instruments, such as swaps, futures and forwards, to hedge anticipated purchases and sales of natural gas, NGLs, crude oil and firm transportation commitments. Interest-rate swaps are also used to manage interest-rate risk. However, derivative instruments do not eliminate the risks. Specifically, such risks include commodity price changes, market supply shortages, interest-rate changes and counterparty default. The impact of these variables could result in our inability to fulfill contractual obligations, significantly higher energy or fuel costs relative to corresponding sales contracts, or increased interest expense.


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We do not hedge fully against commodity price changes, seasonal price differentials, product price differentials or location price differentials. This could result in decreased revenues, increased costs and lower margins, adversely affecting our results of operations.

Our businesses are exposed to market risk and the impact of market fluctuations in natural gas, NGLs and crude oil prices. Market risk refers to the risk of loss of cash flows and future earnings arising from adverse changes in commodity prices. Our primary commodity price exposures arise from:
the value of the NGLs and natural gas we receive as a portion of our compensation for the natural gas gathering and processing services we provide;
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 with respect to our natural gas and NGL transportation businesses;
the seasonal price differentials in natural gas and NGLs related to our storage operations; and
the fuel costs and the value of the retained fuel in-kind in our natural gas pipelines and storage operations.

To manage the risk from market price fluctuations in natural gas, NGLs and crude oil prices, we may use derivative instruments such as swaps, futures, forwards and options. However, we do not hedge fully against commodity price changes and, we therefore retain some exposure to market risk. Accordingly, any adverse changes to commodity prices could result in decreased revenue and increased costs.

Our use of financial instruments and physical forward transactions to hedge market-risk exposure to commodity price and interest-rate fluctuations may result in reduced income.

We utilize financial instruments and physical forward transactions to mitigate our exposure to interest rate and commodity price fluctuations. Hedging instruments that are used to reduce our exposure to interest-rate fluctuations could expose us to risk of financial loss where we have contracted for variable-rate swap instruments to hedge fixed-rate instruments and the variable rate exceeds the fixed rate. In addition, these hedging arrangements may limit the benefit we would otherwise receive if we had contracted for fixed-rate swap agreements to hedge variable-rate instruments and the variable rate falls below the fixed rate. Hedging arrangements that are used to reduce our exposure to commodity price fluctuations limit the benefit we would otherwise receive if market prices for natural gas, crude oil and NGLs exceed the stated price in the hedge instrument for these commodities.

Demand for natural gas and for certain of our products and services is highly weather sensitive and seasonal.

The demand for natural gas and for certain of our products, such as propane, is weather sensitive and seasonal, with a portion of revenues derived from sales for heating during the winter months. Weather conditions influence directly the volume of, among other things, natural gas and propane delivered to customers. Deviations in weather from normal levels and the seasonal nature of certain of our segments can create variations in earnings and short-term cash requirements.

Energy efficiency and technological advances may affect the demand for natural gas and affect adversely our operating results.

More strict local, state and federal energy-conservation measures in the future or technological advances in heating, including installation of improved insulation and the development of more efficient furnaces, energy generation or other devices could affect the demand for natural gas and adversely affect our results of operations and cash flows.

Changes in interest rates could affect adversely our business.

We use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our short-term borrowings. From time to time we use interest-rate derivatives to hedge interest obligations on specific debt issuances, including anticipated debt issuances. These hedges may be ineffective, and our results of operations, cash flows and financial position could be adversely affected by significant fluctuations in interest rates from current levels.


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Our established risk-management policies and procedures may not be effective, and employees may violate our risk-management policies.

We have developed and implemented a comprehensive set of policies and procedures that involve both our senior management and the Audit Committee of ONEOK Partners GP’s Board of Directors to assist us in managing risks associated with, among other things, the marketing, trading and risk-management activities associated with our business segments. Our risk policies and procedures are intended to align strategies, processes, people, information technology and business knowledge so that risk is managed throughout the organization. As conditions change and become more complex, current risk measures may fail to assess adequately the relevant risk due to changes in the market and the presence of risks previously unknown to us. Additionally, if employees fail to adhere to our policies and procedures or if our policies and procedures are not effective, potentially because of future conditions or risks outside of our control, we may be exposed to greater risk than we had intended. Ineffective risk-management policies and procedures or violation of risk-management policies and procedures could have an adverse effect on our earnings, financial position or cash flows.

We may not be able to develop and execute growth projects and acquire new assets which could result in reduced cash distributions to our unitholders.

Our primary business objectives are to generate cash flow sufficient to pay quarterly cash distributions to our unitholders and to increase our quarterly cash distributions over time. Our ability to maintain and grow our distributions to unitholders depends on the growth of our existing businesses and strategic acquisitions. If we are unable to implement business development opportunities and finance such activities on economically acceptable terms, our future growth will be limited, which could adversely impact our results of operations and cash flows and, accordingly, result in reduced cash distributions over time.

Growing our business by constructing new pipelines and plants or making modifications to our existing facilities subjects us to construction risk and supply risks, should adequate natural gas or NGL supply be unavailable upon completion of the facilities.

One of the ways we may grow our businesses is through the construction of new pipelines and new gathering, processing, storage and fractionation facilities and through modifications to our existing pipelines and existing gathering, processing, storage and fractionation facilities. The construction and modification of pipelines and gathering, processing, storage and fractionation facilities may face the following risks:
projects may require significant capital expenditures, which may exceed our estimates, and involves 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 have only limited natural gas or NGL supply committed to these facilities prior to their construction;
we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize;
we may rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves; 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.
As a result, new facilities may not be able to attract enough natural gas or NGLs to achieve our expected investment return, which could affect materially and adversely our results of operations, financial condition and cash flows.

We may not be able to make additional strategic acquisitions or investments.

Our ability to make strategic acquisitions and investments will depend on:
the extent to which acquisitions and investment opportunities become available;
our success in bidding for the opportunities that do become available;
regulatory approval, if required, of the acquisitions or investments on favorable terms; and

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

If we are unable to make strategic investments and acquisitions, we may be unable to grow.

Acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per-unit basis.

Any acquisition involves potential risks that may include, among other things:
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, for which our indemnity is inadequate or for which 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.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and investors will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our resources to future acquisitions.

We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and equipment, which could disrupt our operations.

We do not own all of the land on which certain of our pipelines and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could have a material adverse effect on our financial condition, results of operations and cash flows.

Our operations are subject to operational hazards and unforeseen interruptions, which could affect materially and adversely our business and for which we may not be adequately insured.

Our operations are subject to all of the risks and hazards typically associated with the operation of natural gas and natural gas liquids gathering, transportation and distribution pipelines, storage facilities and processing and fractionation plants. Operating risks include, but are not limited to, leaks, pipeline ruptures, the breakdown or failure of equipment or processes and the performance of pipeline facilities below expected levels of capacity and efficiency. Other operational hazards and unforeseen interruptions include adverse weather conditions, accidents, explosions, fires, the collision of equipment with our pipeline facilities (for example, this may occur if a third party were to perform excavation or construction work near our facilities) and catastrophic events such as tornados, hurricanes, earthquakes, floods or other similar events beyond our control. It is also possible that our facilities could be direct targets or indirect casualties of an act of terrorism. A casualty occurrence might result in injury or loss of life, extensive property damage or environmental damage. Liabilities incurred and interruptions to the operations of our pipeline or other facilities caused by such an event could reduce revenues generated by us and increase expenses, thereby impairing our ability to meet our obligations. Insurance proceeds may not be adequate to cover all liabilities or expenses incurred or revenues lost, and we are not fully insured against all risks inherent to our business.

As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Consequently, we may not be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse

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effect on our financial position and results of operations. Further, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

Terrorist attacks directed at our facilities could adversely affect our business.

The United States government has issued warnings that energy assets, specifically the nation’s pipeline infrastructure, may be future targets of terrorist organizations. These developments may subject our operations to increased risks. Any future terrorist attack that may target our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.

Pipeline safety laws and regulations may impose significant costs and liabilities.

New pipeline safety legislation that was signed into law in 2012, The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), directed the Secretary of Transportation to promulgate new safety regulations for natural gas and hazardous liquids pipelines, including expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength of certain pipelines and operator verification of records confirming the maximum allowable pressure of certain gas transmission pipelines. The 2011 Pipeline Safety Act also increased the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day and also from $1 million to $2 million for a related series of violations. These regulations could cause us to incur capital and operating expenditures for pipeline replacements or repairs, additional monitoring equipment or more frequent inspections or testing of our pipeline facilities, preventive or mitigating measures and other tasks that could result in higher operating costs or capital expenditures.

Compliance with environmental regulations that we are subject to may be difficult and costly.

We are subject to multiple environmental laws and regulations affecting many aspects of present and future operations, including air emissions, water quality, wastewater discharges, solid and hazardous wastes, and hazardous material and substance management. These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with these laws, regulations, permits and licenses may expose us to fines, penalties and/or interruptions in our operations that could be material to our results of operations. If a leak or spill of hazardous substance occurs from our pipelines, gathering lines or facilities in the process of transporting natural gas or NGLs or at any facility that we own, operate or otherwise use, we could be held jointly and severally liable for all resulting liabilities, including investigation and clean-up costs, which could affect materially our results of operations and cash flows. In addition, emission controls required under the federal Clean Air Act and similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot assure that existing environmental regulations will not be revised or that new regulations will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from customers, could have a material adverse effect on our business, financial condition and results of operations.

Our operations are subject to federal and state laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities.

The risk of incurring substantial environmental costs and liabilities is inherent in our business. Our operations are subject to extensive federal, state and local laws and regulations governing the discharge of materials into, or otherwise relating to the protection of, the environment. Examples of these laws include:
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 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.

Various federal and state governmental authorities, including the EPA, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators are subject to administrative, civil and criminal penalties,

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including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under the CERCLA, Resource Conservation and Recovery Act and analogous state laws for the remediation of contaminated areas.

There is an inherent risk of incurring environmental costs and liabilities in our business due to our handling of the products we gather, transport, process and store, air emissions related to our operations, past industry operations and waste disposal practices, some of which may be material. Private parties, including the owners of properties through which our pipeline systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites we operate are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could increase significantly our compliance costs and the cost of any remediation that may become necessary, some of which may be material. Additional information is included under Item 1, Business, under “Regulatory, Environmental and Safety Matters” and in Note O of the Notes to Consolidated Financial Statements in this Annual Report.

Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage in the event an environmental claim is made against us. Our business may be affected materially and adversely by increased costs due to stricter pollution-control requirements or liabilities resulting from noncompliance with required operating or other regulatory permits. New environmental regulations might also materially and adversely affect our products and activities, and federal and state agencies could impose additional safety requirements, all of which could affect materially our profitability.

We may face significant costs to comply with the regulation of GHG emissions.

GHG emissions originate primarily from combustion engine exhaust, heater exhaust and fugitive methane gas emissions. Various federal and state legislative proposals have been introduced to regulate the emission of GHGs, particularly carbon dioxide and methane, and the United States Supreme Court has ruled that carbon dioxide is a pollutant subject to regulation by the EPA. In addition, there have been international efforts seeking legally binding reductions in emissions of GHGs.

We believe it is likely that future governmental legislation and/or regulation may require us either to limit GHG emissions from our operations or to purchase allowances for such emissions that are actually attributable to our NGL customers. However, we cannot predict precisely what form these future regulations will take, the stringency of the regulations or when they will become effective. Several legislative bills have been introduced in the United States Congress that would require carbon dioxide emission reductions. Previously considered proposals have included, among other things, limitations on the amount of GHGs that can be emitted (so called “caps”) together with systems of permitted emissions allowances. These proposals could require us to reduce emissions, even though the technology is not currently available for efficient reduction, or to purchase allowances for such emissions. Emissions also could be taxed independently of limits.

In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner and/or independent of federal regulation. These regulations could be more stringent than any federal legislation that is adopted.

Future legislation and/or regulation designed to reduce GHG emissions could make some of our activities uneconomic to maintain or operate. Further, we may not be able to pass on the higher costs to our customers or recover all costs related to complying with GHG regulatory requirements. Our future results of operations, cash flows or financial condition could be adversely affected if such costs are not recovered through regulated rates or otherwise passed on to our customers.

We continue to monitor legislative and regulatory developments in this area. Although the regulation of GHG emissions may have a material impact on our operations and rates, we believe it is premature to attempt to quantify the potential costs of the impacts.

We are subject to physical and financial risks associated with climate change.

There is a growing belief that emissions of GHGs may be linked to global climate change. Climate change creates physical and financial risk. Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions may be affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our operating territory could also have an impact on our

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revenues. Severe weather impacts our operating territories primarily through hurricanes, thunderstorms, tornados and snow or ice storms. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could affect negatively our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Our business could be affected by the potential for lawsuits against GHG emitters, based on links drawn between GHG emissions and climate change.

Continued development of new supply sources could impact demand.

The discovery of nonconventional natural gas production areas nearer to certain of the market areas that we serve may compete with natural gas originating in production areas connected to our systems. For example, the Marcellus Shale in Pennsylvania, West Virginia and Ohio, may cause natural gas in supply areas connected to our systems to be diverted to markets other than our traditional market areas and may affect capacity utilization adversely on our pipeline systems and our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows. In addition, supply volumes from these nonconventional natural gas production areas may compete with and displace volumes from the Mid-Continent, Permian, Rocky Mountains and Canadian supply sources in certain of our markets. In our Natural Gas Gathering and Processing segment, the development of these new nonconventional reserves could move drilling rigs from our current service areas to other areas, which may reduce demand for our services. In our Natural Gas Pipelines segment, the displacement of natural gas originating in supply areas connected to our pipeline systems by these new supply sources that are closer to the end-use markets could result in lower transportation revenues, which could have a material adverse impact on our business, financial condition, results of operations and cash flows.

Increased regulation of exploration and production activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new crude oil and natural gas wells, which could adversely impact our revenues by decreasing the volumes of natural gas and NGLs transported on our or our joint ventures’ natural gas and natural gas liquids pipelines.

The natural gas industry is relying increasingly on natural gas supplies from nonconventional sources, such as shale and tight sands. Natural gas extracted from these sources frequently requires hydraulic fracturing, which involves the pressurized injection of water, sand and chemicals into a geologic formation to stimulate natural gas production. Recently, there have been initiatives at the federal and state levels to regulate or otherwise restrict the use of hydraulic fracturing or the disposal of waste water used in the hydraulic fracturing process, and several states have adopted regulations that impose more stringent permitting, disclosure and well-completion requirements on hydraulic fracturing operations. Legislation or regulations placing restrictions on hydraulic fracturing activities, including waste-water disposal, could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of unprocessed natural gas and, in turn, adversely affect our revenues and results of operations by decreasing the volumes of unprocessed natural gas and NGLs gathered, treated, processed, fractionated and transported on our or our joint ventures’ natural gas and natural gas liquids pipelines, several of which gather unprocessed natural gas from areas where the use of hydraulic fracturing is prevalent.

In the competition for customers, we may have significant levels of uncontracted or discounted capacity on our natural gas and natural gas liquids pipelines, processing, fractionation and storage assets.

Our natural gas and natural gas liquids pipelines, processing, fractionation and storage assets compete with other pipelines, processing, fractionation and storage facilities for natural gas and NGL supply delivered to the markets we serve. As a result of competition, we may have significant levels of uncontracted or discounted capacity on our pipelines, processing, fractionation and in our storage assets, which could have a material adverse impact on our results of operations.

If production from the Western Canada Sedimentary Basin remains flat or declines and demand for natural gas from the Western Canada Sedimentary Basin is greater in market areas other than the Midwestern United States, demand for our interstate transportation services could decrease significantly.

We depend on a portion of natural gas supply from the Western Canada Sedimentary Basin for some of our interstate pipelines, primarily Viking Gas Transmission and our investment in Northern Border Pipeline, that transport Canadian natural gas from the Western Canada Sedimentary Basin to the Midwestern United States market area. If demand for natural gas increases in Canada or other markets not served by our pipelines and/or production remains flat or declines, demand for transportation service on our interstate natural gas pipelines could decrease significantly, which could adversely impact our business, financial condition, results of operations and cash flows.

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We may not be able to replace, extend or add additional customer contracts or contracted volumes on favorable terms, or at all, which could affect our financial condition, the amount of cash available to pay distributions and our ability to grow.

Although many of our customers and suppliers are subject to long-term contracts, if we are unable to replace or extend such contracts, add additional customers or otherwise increase the contracted volumes of natural gas and NGLs provided to us by current producers, in each case on favorable terms, if at all, our financial condition, growth plans and the amount of cash available to pay distributions could be adversely affected. Our ability to replace, extend or add additional customer or supplier contracts, or increase contracted volumes of natural gas and NGLs from current producers, on favorable terms, or at all, is subject to a number of factors, some of which are beyond our control, including:
the level of existing and new competition in our businesses or from alternative fuel sources, such as electricity, coal, fuel oils or nuclear energy;
natural gas and NGL prices, demand, availability; and
margins in our markets.

Mergers between our customers and competitors could result in lower volumes being gathered, processed, fractionated, transported or stored on our assets, thereby reducing the amount of cash we generate.

Mergers between our existing customers and our competitors could provide strong economic incentives for the combined entities to utilize their existing gathering, processing, fractionation and/or transportation systems instead of ours in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers, and we could experience difficulty in replacing those lost volumes and revenues. Because most of our operating costs are fixed, a reduction in volumes could result not only in less revenue but also in a decline in cash flow, which would reduce our ability to pay cash distributions to our unitholders.

Our business is subject to regulatory oversight and potential penalties.

The natural gas industry historically has been subject to heavy state and federal regulation that extends to many aspects of our businesses and operations, including:
rates, operating terms and conditions of service;
the types of services we may offer our 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.

Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair our ability to compete for business or to recover costs and may increase the cost and burden of operations.
We cannot guarantee that state or federal regulators will authorize any projects or acquisitions that we may propose in the future. Moreover, there can be no guarantee that, if granted, any such authorizations will be made in a timely manner or will be free from potentially burdensome conditions.

Failure to comply with all applicable state or federal statutes, rules and regulations and orders could bring substantial penalties and fines. For example, under the Energy Policy Act of 2005, the FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1 million per day for each violation.

Finally, we cannot give any assurance regarding future state or federal regulations under which we will operate or the effect such regulations could have on our business, financial condition, results of operations and cash flows.

Our regulated pipelines’ transportation rates are subject to review and possible adjustment by federal and state regulators.

Under the Natural Gas Act, which is applicable to interstate natural gas pipelines, and the Interstate Commerce Act, which is applicable to crude oil and natural gas liquids pipelines, our interstate transportation rates, which are regulated by the FERC, must be just and reasonable and not unduly discriminatory.

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Shippers may protest our pipeline tariff filings, and the FERC and or state regulatory agency may investigate tariff rates. Further, the FERC may order refunds of amounts collected under newly filed rates that are determined by the FERC to be in excess of a just and reasonable level. In addition, shippers may challenge by complaint the lawfulness of tariff rates that have become final and effective. The FERC and/or state regulatory agencies also may investigate tariff rates absent shipper complaint. Any finding that approved rates exceed a just and reasonable level on the natural gas pipelines would take effect prospectively. In a complaint proceeding challenging natural gas liquids pipeline rates, if the FERC determines existing rates exceed a just and reasonable level, it could require the payment of reparations to complaining shippers for up to two years prior to the complaint. Any such action by the FERC or a comparable action by a state regulatory agency could affect adversely our pipeline businesses’ ability to charge rates that would cover future increases in costs, or even to continue to collect rates that cover current costs, and provide for a reasonable return. We can provide no assurance that our pipeline systems will be able to recover all of their costs through existing or future rates.

We are subject to comprehensive energy regulation by governmental agencies, and the recovery of our costs are dependent on regulatory action.

Federal, state and local agencies have jurisdiction over many of our activities, including regulation by the FERC of our interstate pipeline assets. The profitability of our regulated operations is dependent on our ability to pass through costs related to providing energy and other commodities to our customers by filing periodic rate cases. The regulatory environment applicable to our regulated businesses could impair our ability to recover costs historically absorbed by our customers.

We are unable to predict the impact that the future regulatory activities of these agencies will have on our operating results. Changes in regulations or the imposition of additional regulations could have an adverse impact on our business, financial condition and results of operations.

Our regulated pipeline companies have recorded certain assets that may not be recoverable from our customers.

Accounting policies for FERC-regulated companies permit certain assets that result from the regulated rate-making process to be recorded on our balance sheet that could not be recorded under GAAP for nonregulated entities. We consider factors such as regulatory changes and the impact of competition to determine the probability of future recovery of these assets. If we determine future recovery is no longer probable, we would be required to write off the regulatory assets at that time.

Some of our nonregulated businesses have a higher level of risk than our regulated businesses.

Some of our nonregulated operations, which include our natural gas gathering and processing business and most of our natural gas liquids business, have a higher level of risk than our regulated operations, which includes a portion of our natural gas pipelines business and a portion of our natural gas liquids business. We expect to continue investing in natural gas and natural gas liquids projects and other related projects, some or all of which may involve nonregulated businesses or assets. These projects could involve risks associated with operational factors, such as competition and dependence on certain suppliers and customers; and financial, economic and political factors, such as rapid and significant changes in commodity prices, the cost and availability of capital and counterparty risk, including the inability of a counterparty, customer or supplier to fulfill a contractual obligation.

A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs, which could affect operations and cash flows available for distribution to our unitholders.

Our operations require skilled and experienced workers with proficiency in multiple tasks. In recent years, a shortage of workers trained in various skills associated with the midstream energy business has caused us to conduct certain operations without full staff, thus hiring outside resources, which may decrease our productivity and increase our costs. This shortage of trained workers is the result of experienced workers reaching retirement age and increased competition for workers in certain areas, combined with the difficulty of attracting new workers to the midstream energy industry. This shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our operations and cash flows available for distribution to our unitholders.


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We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could affect adversely our financial results.

The workplaces associated with our facilities are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. The failure to comply with OSHA requirements or general industry standards, including keeping adequate records or monitoring occupational exposure to regulated substances, could expose us to civil or criminal liability, enforcement actions, and regulatory fines and penalties and could have a material adverse effect on our business, financial position, results of operations and cash flows.

Measurement adjustments on our pipeline system can be impacted materially by changes in estimation, type of commodity and other factors.

Natural gas and natural gas liquids measurement adjustments occur as part of the normal operating conditions associated with our assets. The quantification and resolution of measurement adjustments are complicated by several factors including: (1) the significant quantities (i.e., thousands) of measurement equipment that we use throughout our natural gas and natural gas liquids systems, primarily around our gathering and processing assets; (2) varying qualities of natural gas in the streams gathered and processed through our systems and the mixed nature of NGLs gathered and fractionated; and (3) variances in measurement that are inherent in metering technologies. Each of these factors may contribute to measurement adjustments that can occur on our systems, which could negatively affect our business, financial position, results of operations and cash flows.

Many of our pipeline and storage assets have been in service for several decades.

Many of our pipeline and storage assets are designed as long-lived assets. Over time the age of these assets could result in increased maintenance or remediation expenditures and an increased risk of product releases and associated costs and liabilities. Any significant increase in these expenditures, costs or liabilities could materially adversely affect our results of operations, financial position or cash flows, as well as our ability to pay cash distributions.

A breach of information security, including a cybersecurity attack, or failure in of one or more key information technology or operational systems, or those of third parties, may affect adversely our operations, financial results or reputation.

Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions. The various uses of these IT systems, networks and services include, but are not limited to:
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 or tax requirements;
providing data security; and
handling other processing necessary to manage our business.

If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to perform critical functions, which could adversely affect our business and results of operations. Our financial results could also be affected adversely if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our businesses. We use computer programs to help run our financial and operations organizations, and this may subject our business to increased risks. In recent years, there has been a rise in the number of cyberattacks on companies’ network and information systems by both state-sponsored and criminal organizations, and as a result, the risks associated with such an event continue to increase. A significant failure, compromise, breach or interruption in our systems could result in a disruption of our operations, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. If any such failure, interruption or similar event results in the improper disclosure of information maintained in our information systems and

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networks or those of our vendors, including personnel, customer and vendor information, we could also be subject to liability under relevant contractual obligations and laws and regulations protecting personal data and privacy. Efforts by us and our vendors to develop, implement and maintain security measures may not be successful in preventing these events from occurring, and any network and information systems-related events could require us to expend significant resources to remedy such event. Although we believe that we have robust information security procedures and other safeguards in place, as cyberthreats continue to evolve, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

Cyberattacks against us or others in our industry could result in additional regulations. Current efforts by the federal government, such as the Improving Critical Infrastructure Cybersecurity executive order, and any potential future regulations could lead to increased regulatory compliance costs, insurance coverage cost or capital expenditures. We cannot predict the potential impact to our business or the energy industry resulting from additional regulations.

If we fail to maintain an effective system of internal controls, we may not be able to report accurately our financial results or prevent fraud. As a result, current and potential holders of our equity and debt securities could lose confidence in our financial reporting, which would harm our business and cost of capital.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint-venture participants agree.

We participate in several joint ventures. Due to the nature of some of these arrangements, each participant in these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment, as well as any other assets that may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features customarily include a corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100 percent) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, transactions with affiliates of a joint-venture participant, litigation and transactions not in the ordinary course of business, among others. Thus, without the concurrence of joint-venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of us or the particular joint venture.

Moreover, any joint-venture owner generally may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint-venture owners. Any such transaction could result in us being required to partner with different or additional parties.

An impairment of goodwill, long-lived assets, including intangible assets, and equity-method investments could reduce our earnings.

Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill and intangible assets with indefinite useful lives for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. For example, if the current depressed energy commodity price environment persists for a prolonged period or further declines, it could result in lower volumes delivered to our systems and impairments of our assets or equity-method investments. If we determine that an impairment is indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization.

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We may engage in acquisitions, divestitures and other strategic transactions, the success of which may impact our results of operations.

We may engage in acquisitions, divestitures and other strategic transactions. If we are unable to integrate successfully businesses that we acquire with our existing business, our results of operations may be affected materially and adversely. Similarly, we may from time to time divest portions of our business, which may also affect materially and adversely our results of operations.

RISKS INHERENT IN AN INVESTMENT IN US

Our general partner's absolute discretion in determining our level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our Partnership Agreement requires our general partner to deduct from available cash the amount of any cash reserves that it determines in its reasonable discretion are necessary to fund our future operating expenditures for the proper conduct of our business, to comply with applicable laws or agreements to which we are a party and to provide funds for future distributions to partners. Any such cash reserves will reduce the amount of cash currently available for distribution to our unitholders.

ONEOK’s sale of substantial amounts of common units could reduce the market price of our common units.

ONEOK and its affiliates own all of the Class B units, 41.3 million common units and the entire 2 percent general partner interest in us, which together constituted a 41.2 percent ownership interest in us as of December 31, 2015. The Class B units are eligible to convert into common units on a one-for-one basis at ONEOK’s option. ONEOK may, from time to time, sell all or a portion of its common units. Sales of substantial amounts of its common units or other types of units, or the anticipation of such sales, could lower the market price of our common units and may make it more difficult for us to sell our equity securities in the future at a time and price that we deem appropriate.

ONEOK could withdraw the waiver of its right to receive on its Class B units 110 percent of the distributions paid with respect to our common units.

At a special meeting of the holders of our common units held on May 10, 2007, the proposed amendments to our Partnership Agreement were not approved by the required two-thirds affirmative vote of our outstanding units, excluding the common units and Class B limited partner units held by ONEOK and its affiliates. As a result, effective April 7, 2007, ONEOK, as the sole holder of our Class B limited partner units, became entitled to receive increased quarterly distributions on its Class B units equal to 110 percent of the distributions paid with respect to our common units.

On June 21, 2007, ONEOK waived its right to receive the increased quarterly distributions on the Class B units for the period of April 7, 2007, through December 31, 2007, and continuing thereafter until ONEOK gives us no less than 90 days advance notice that it has withdrawn its waiver. ONEOK could withdraw such waiver and begin receiving such increased distributions, effective with respect to any distribution on the Class B units declared or paid on or after 90 days following delivery of the notice.

If our unitholders vote to remove ONEOK or its affiliates as our general partner, quarterly distributions and distributions payable to ONEOK upon liquidation of the Class B units would increase.

Since the proposed amendments to our Partnership Agreement were not approved by the requisite number of our common unitholders, if our common unitholders vote at any time to remove ONEOK or its affiliates as our general partner, quarterly distributions payable on the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units, and distributions payable upon liquidation of the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units.

Our unitholders have limited voting rights and are not entitled to elect our general partner’s directors, which could lower the trading price of our common units. In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders have no right

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to elect our general partner or its directors on an annual or other continuing basis. The Board of Directors of our general partner, including the independent directors, is chosen by the owners of the general partner and not by the unitholders.

Furthermore, if unitholders are dissatisfied with the performance of our general partner, it may be difficult to remove ONEOK Partners GP or its officers or directors. ONEOK Partners GP may not be removed except upon the affirmative vote of the holders of at least two thirds of our outstanding units voting together as a single class (excluding units held by ONEOK Partners GP and its affiliates). As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence or reduction of a takeover premium in the trading price.

We do not operate all of our assets nor do we employ directly any of the persons responsible for providing us with administrative, operating and management services. This reliance on others to operate our assets and to provide other services could adversely affect our business and operating results.

We rely on ONEOK and ONEOK Partners GP to provide us with administrative, operating and management services. We have a limited ability to control our operations and the associated costs of such operations. The success of these operations depends on a number of factors that are outside our control, including the competence and financial resources of the provider. ONEOK and ONEOK Partners GP may outsource some or all of these services to third parties, and a failure to perform by these third-party providers could lead to delays in or interruptions of these services. Should ONEOK and ONEOK Partners GP not perform their respective contractual obligations, we may have to contract elsewhere for these services, which may cost more than we are currently paying. In addition, we may not be able to obtain the same level or kind of service or retain or receive the services in a timely manner, which may impact our ability to perform under our contracts and negatively affect our business and operating results. Our reliance on ONEOK and ONEOK Partners GP and third-party providers with which they contract, together with our limited ability to control certain costs, could harm our business and results of operations.

Our Partnership Agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our Partnership Agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our Partnership Agreement:
permits our general partner to make a number of decisions considering only the interests and factors beneficial to itself or its parent, ONEOK, that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination (through its Board of Directors) whether to consent to any merger or consolidation of us;
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in “good faith,” meaning it believed the decision was in, or not inconsistent with, our best interests;
provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decision is in, or not inconsistent with, our best interests;
provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our general partner in “good faith,” and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
provides that our general partner and its affiliates, officers and directors will be indemnified by the Partnership for any acts or omissions so long as such person acted in “good faith” and in a manner believed to be in, or not opposed to, the best interest of us and, with respect to any criminal proceeding, had no reasonable cause to believe its conduct was unlawful.

By purchasing a common unit, a common unitholder will be bound by the provisions in our Partnership Agreement, including the provisions discussed above.


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The Board of Directors of our general partner, our general partner and its affiliates have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests.

ONEOK owns 100 percent of our general partner interest, and as a result of our public offerings of common units and units sold under our “at-the-market” equity program, ONEOK and its subsidiaries owned a 41.2 percent aggregate equity interest in us at December 31, 2015. Our Partnership Agreement limits any fiduciary duties owed by our general partner and ONEOK to those duties that are stated specifically in our Partnership Agreement. Although ONEOK, through the Board of Directors of our general partner, has an obligation to manage us in a manner that is in, or not inconsistent with, our best interests, the Board of Directors of ONEOK has a fiduciary duty to manage our general partner in a manner beneficial to ONEOK. Five of the eight members of the Board of Directors of our general partner are either members of ONEOK’s Board of Directors or executive management of ONEOK. Three independent members and one management member of the Board of Directors of our general partner also are members of ONEOK’s Board of Directors, with the management member being the only management member of ONEOK’s Board of Directors. Conflicts of interest may arise between ONEOK and its other affiliates and between us and our unitholders. In resolving these conflicts, our general partner may determine that the transaction is “fair and reasonable” to us, without the agreement of any other party, including the Audit or Conflicts Committees. In that regard, our general partner may favor its own interests and the interests of its other affiliates over the interests of our unitholders, as long as it does not take action that conflicts with our Partnership Agreement. These conflicts include, among others, the following situations:
our general partner, which is owned by ONEOK, and the Board of Directors of our general partner are allowed to take into account the interests of parties other than us in resolving conflicts of interest, which has the effect of limiting their fiduciary duties to our unitholders;
our Partnership Agreement limits the liability and reduces the fiduciary duties of the members of the Board of Directors of our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
the Board of Directors of our general partner determines the amount and timing of our cash reserves, asset purchases and sales, capital expenditures, borrowings and issuances of additional partnership securities, each of which can affect the amount of cash that is distributed to our unitholders;
the Board of Directors of our general partner approves the amount and timing of any capital expenditures and determines whether they are maintenance capital expenditures or growth capital expenditures, which can affect the amount of cash that is distributed to our unitholders;
the Board of Directors of our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
our Partnership Agreement provides that costs incurred by the Board of Directors, our general partner and its affiliates in the conduct of our business are reimbursable by us;
our Partnership Agreement does not restrict the members of the Board of Directors of our general partner from causing us to pay the Board of Directors, our general partner or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
our general partner may exercise its limited right to call and purchase common units, which right may be assigned or transferred to, among others, us or affiliates of the general partner, if the general partner and its affiliates own 80 percent or more of the common units; and
the Board of Directors and Audit and Conflicts Committees of our general partner decide whether to retain separate counsel, accountants or others to perform services for us.

Our general partner and its affiliates may compete directly with us and have no obligation to present business opportunities to us.

ONEOK and its affiliates are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. ONEOK may acquire, construct or dispose of additional midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets. In addition, under our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to ONEOK and its affiliates. As a result, neither ONEOK nor any of its affiliates has any obligation to present business opportunities to us.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer all, or any part of, its general partner interest to a third party without the consent of the unitholders. The members, shareholders or unitholders, as the case may be, of our new general partner may then be in a position to replace all or a portion of the directors of our general partner with their own choices and to possibly control the decisions made by the Board of Directors of our general partner.


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Any reduction in our credit ratings could affect materially and adversely our business, financial condition, liquidity and results of operations.

Our senior unsecured long-term debt and commercial paper program have been assigned an investment-grade rating of “Baa2” (Negative) and Prime-2, respectively, by Moody’s and “BBB” (Negative) and A-2, respectively, by S&P.  We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.  Specifically, if Moody’s or S&P were to downgrade our long-term debt or commercial paper program rating, particularly below investment grade, our borrowing costs would increase, which would affect adversely our financial results, and our potential pool of investors and funding sources could decrease. Ratings from credit agencies are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating.

Increases in interest rates may cause the market price of our common units to decline.

An increase in interest rates may cause a corresponding decline in demand for equity investments in general and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our Partnership Agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt- service requirements, all of which are significant. The value of our units and other limited partner interests may decrease in correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity or incur more debt to recapitalize.

An event of default may require us to offer to repurchase certain of our senior notes or may impair our ability to access capital.

The indentures governing our senior notes include an event of default upon the acceleration of other indebtedness of $100 million or more. Such an event of default would entitle the trustee or the holders of 25 percent in aggregate principal amount of the outstanding senior notes to declare those senior notes immediately due and payable in full. We may not have sufficient cash on hand to repurchase and repay any accelerated senior notes, which may cause us to borrow money under our credit facilities or seek alternative financing sources to finance the repayments and repurchases. We could also face difficulties accessing capital or our borrowing costs could increase, impacting our ability to obtain financing for acquisitions or capital expenditures, to refinance indebtedness and to fulfill our debt obligations.

Our indebtedness could impair our financial condition and our ability to fulfill our obligations.

As of December 31, 2015, we had total indebtedness of approximately $7.3 billion. Our indebtedness could have significant consequences. For example, it could:
make it more difficult for us to satisfy our obligations with respect to our senior notes and our other indebtedness, 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, thereby reducing the availability of cash for working capital, capital expenditures, acquisitions, distributions to partners and general partnership 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.

We are not prohibited under the indentures governing our senior notes from incurring additional indebtedness, but our debt agreements do subject us to certain operational limitations summarized in the next paragraph. Our incurrence of significant additional indebtedness would exacerbate the negative consequences mentioned above and could affect adversely our ability to repay our senior notes and other indebtedness.

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Our debt agreements contain provisions that restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, certain of these agreements contain provisions that, among other things, limit our ability to make loans or investments, make material changes to the nature of our business, merge, consolidate or engage in asset sales, grant liens or make negative pledges. Certain agreements also require us to maintain certain financial ratios, which limit the amount of additional indebtedness we can incur. For example, our Partnership Credit Agreement contains a financial covenant requiring us to maintain a ratio of indebtedness to adjusted EBITDA (EBITDA, as defined in our Partnership 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. If we consummate one or more acquisitions in which the aggregate purchase price is $25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will increase to 5.5 to 1 for the quarter in which the acquisition was completed and the two following quarters.

These restrictions could result in higher costs of borrowing and impair our ability to generate additional cash. Future financing agreements we may enter into may contain similar or more restrictive covenants.

If we are unable to meet our debt-service obligations, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing, raise equity or sell assets on satisfactory terms, or at all.

Borrowings under our Partnership Credit Agreement and our senior notes are nonrecourse to ONEOK, and ONEOK does not guarantee our debt, commercial paper or other similar commitments.

We and the Intermediate Partnership have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We and the Intermediate Partnership are holding companies, and our subsidiaries conduct all of our operations and own all of our operating assets. Neither we nor the Intermediate Partnership have significant assets other than the Partnership interests and the equity in our subsidiaries and other investments. As a result, our ability to make quarterly distributions and required payments on our indebtedness depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, credit facilities, applicable state partnership laws, and other laws and regulations, including FERC policies. If we are unable to obtain the funds necessary to make quarterly distributions or required payments on our indebtedness, we may be required to adopt one or more alternatives, such as refinancing the indebtedness or seeking alternative financing sources to fund the quarterly distributions and indebtedness payments.

We may issue additional common units or other units without unitholder approval, which would dilute unitholders’ ownership interests.

Our general partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional units. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
our unitholders’ proportionate ownership interest in us will decrease;
the distributions to our general partner related to its incentive distribution rights may increase and the distribution paid on each unit may decrease;
the relative voting strength of each previously outstanding unit may be diminished; and
the market price of the common units may decline.

Notwithstanding the foregoing, the issuance of equity securities ranking senior to the common units requires approval of a majority of the outstanding common units.

In addition, whenever we issue equity securities to any person other than our general partner and its affiliates, our general partner has the right, under the Partnership Agreement, which it may from time to time assign in whole or in part to any of its affiliates, to purchase additional partnership interests on the same terms as they are issued to other purchasers. This allows our general partner and its affiliates to maintain their proportionate partnership interest in us. No other unitholder has a similar right. Therefore, only the general partner may protect itself against dilution caused by issuance of additional equity interests.


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Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own 80 percent or more of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders also may incur a tax liability upon the sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our Partnership Agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units subsequently were deregistered, we would no longer be subject to the reporting requirements of the Exchange Act.

Our Partnership Agreement restricts the voting rights of unitholders owning 20 percent or more of our common units.

Our Partnership Agreement restricts unitholders’ voting rights by providing that any units held by a person or entity that owns 20 percent or more of our common units then outstanding, other than our general partner and its affiliates, cannot vote on any matter. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

A general partner of a limited partnership generally has unlimited liability for the obligations of the partnership, such as debts and environmental liabilities, except for those contractual obligations of the partnership that are made expressly without recourse to the general partner. We are organized as a limited partnership under Delaware law, and we and our subsidiaries conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be held liable for our obligations to the same extent as a general partner if a court or government agency should determine that (i) we were conducting business in a state but had not complied with that state’s limited partnership statute; or (ii) a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.

Unitholders may have liability to repay distributions.

Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (“Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are nonrecourse to the Partnership are not counted for purposes of determining whether a distribution is permitted.

Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to us for the repayment of the distribution amount. Likewise, upon the winding up of the Partnership, in the event that (a) we do not distribute assets in the following order: (i) to creditors in satisfaction of their liabilities; (ii) to partners and former partners in satisfaction of liabilities for distributions owed under our Partnership Agreement; (iii) to partners for the return of their contributions; and finally (iv) to the partners in the proportions in which the partners share in distributions and (b) a limited partner knows at the time that the distribution violated the Delaware Act, then such limited partner will be liable for a period of three years from the impermissible distribution to repay the distribution under Section 17-804 of the Delaware Act.

A purchaser of common units becomes a limited partner and is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations, if the liabilities could be determined from our Partnership Agreement.


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A court may use fraudulent conveyance considerations to avoid or subordinate the Intermediate Partnership’s guarantee of certain of our senior notes.

Various applicable fraudulent conveyance laws have been enacted for the protection of creditors. In a Florida bankruptcy case, a court ruled that certain guarantees were unenforceable due to fraudulent conveyance laws, among other factors. Similarly, a court may use fraudulent conveyance laws to subordinate or avoid the guarantee of certain of our senior notes issued by the Intermediate Partnership. It is also possible that under certain circumstances a court could hold that the direct obligations of the Intermediate Partnership could be superior to the obligations under that guarantee.

A court could avoid or subordinate the Intermediate Partnership’s guarantee of certain of our senior notes in favor of the Intermediate Partnership’s other debts or liabilities to the extent that the court determined either of the following were true at the time the Intermediate Partnership issued the guarantee:
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 insolvent or rendered insolvent by reason of the issuance of the guarantee;
was engaged or about to engage in a business or transaction for which its remaining assets constituted unreasonably small capital; or
intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured.

The measure of insolvency for purposes of the foregoing will vary depending upon the law of the relevant jurisdiction. Generally, however, an entity would be considered insolvent for purposes of the foregoing if:
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.

Among other things, a legal challenge of the Intermediate Partnership’s guarantee of certain of our senior notes on fraudulent conveyance grounds may focus on the benefits, if any, realized by the Intermediate Partnership as a result of our issuance of such senior notes. To the extent the Intermediate Partnership’s guarantee of certain of our senior notes is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the holders of such senior notes would cease to have any claim in respect of the guarantee.

Our operating cash flow is derived partially from cash distributions we receive from our unconsolidated affiliates.

Our operating cash flow is derived partially from cash distributions we receive from our unconsolidated affiliates, as discussed in Note M of the Notes to Consolidated Financial Statements. The amount of cash that our unconsolidated affiliates can distribute principally depends upon the amount of cash flow these affiliates generate from their respective operations, which may fluctuate from quarter to quarter. We do not have any direct control over the cash distribution policies of our unconsolidated affiliates. This lack of control may contribute to our not having sufficient available cash each quarter to continue paying distributions at our current levels.

Additionally, the amount of cash that we have available for cash distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by noncash items such as depreciation, amortization and provisions for asset impairments. As a result, we may be able to make cash distributions during periods when we record losses and may not be able to make cash distributions during periods when we record net income.

The credit and risk profile of ONEOK Partners GP and its owner could affect adversely our credit ratings and profile.

The credit and business risk profiles of ONEOK Partners GP, and of ONEOK as the owner of ONEOK Partners GP, may be factors in credit evaluations of us as a publicly traded limited partnership due to the significant influence of ONEOK Partners GP and ONEOK over our business activities, including our cash distributions, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of ONEOK Partners GP and its owner, including the degree of their financial leverage and their dependence on cash flow from the Partnership to service their indebtedness. ONEOK is

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dependent on the cash distributions from its general and limited partner equity interests in us to service indebtedness. Any distributions by us to ONEOK will be made only after satisfying our then current obligations to our creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect the separateness of us from the entity that controls ONEOK Partners GP (i.e., ONEOK), our credit ratings and business-risk profile could be affected adversely if the ratings and risk profiles of such entities were viewed as substantially lower or riskier than ours.

The right to receive payments on our outstanding debt securities and subsidiary guarantees is unsecured and will be effectively subordinated to our existing and future secured indebtedness as well as to any existing and future indebtedness of our subsidiaries that do not guarantee the senior notes.

Our debt securities are effectively subordinated to claims of our secured creditors, and the guarantees are effectively subordinated to the claims of our secured creditors as well as the secured creditors of our subsidiary guarantors. Although many of our operating subsidiaries have guaranteed such debt securities, the guarantees are subject to release under certain circumstances, and we may have subsidiaries that are not guarantors. In that case, the debt securities effectively would be subordinated to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the debt securities.

The ability to transfer our debt securities may be limited by the absence of a trading market.

We do not currently intend to apply for listing of our debt securities on any securities exchange or stock market. The liquidity of any market for our debt securities will depend on the number of holders of those debt securities, the interest of securities dealers in making a market in those debt securities and other factors. Accordingly, we can give no assurance as to the development or liquidity of any market for the debt securities.

TAX RISKS

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our common unitholders would be reduced substantially.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter.

Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as a corporate entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35 percent, and would likely pay additional state and local income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our unitholders. Because an income tax would be imposed upon us as a corporation, the cash available for distributions to our common unitholders would be reduced substantially. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated free cash flow and after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.

In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are subject to an entity-level Texas franchise tax. Imposition of any similar taxes by any other state may reduce substantially the cash available for distribution to our common unitholders and, therefore, impact negatively the value of an investment in our common units.

Our Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to additional entity-level taxation for federal, state or local income tax

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purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common or other units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, the President of the United States and members of the United States Congress propose and consider substantive changes to the existing federal income tax laws that could affect the tax treatment of certain publicly traded partnerships. Further, the U.S. Treasury Department and the IRS issued proposed regulations under Section 7704(d)(1)(E) of the Income Tax Code on May 5, 2015, interpreting the scope of qualifying income for publicly traded partnerships by providing industry-specific guidance with respect to activities that will generate qualifying income for purposes of the qualifying income requirement. The proposed regulations, once issued in final form, may change interpretations of the current law relating to the characterization of income as qualifying income and could modify the amount of our gross income we are able to treat as qualifying income for purposes of the qualifying income requirement.

Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any previously considered changes or any other proposals will ultimately be enacted. Any such changes could impact negatively the value of an investment in our common units and the amount of cash available for distribution to our unitholders.

An IRS contest of the federal income tax positions we take may affect adversely the market for our common units, and the costs of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the federal income tax positions we take, and such positions may not ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may affect adversely the taxable income reported to our unitholders and the income taxes they are required to pay. As a result, any such contest with the IRS may affect materially and adversely the market for our common units and the price at which they trade. In addition, the costs of any such contest with the IRS will be borne indirectly by our unitholders and our general partner because such costs will reduce our cash available for distribution.

Recently enacted legislation, applicable to partnership tax years beginning after 2017, alters the procedures for auditing large partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level federal income tax audit. Under the new rules, unless we are eligible to, and do, elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed. If we are required to pay taxes, penalties and interest as a result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited tax year.

A unitholder’s share of our income may be taxable to the unitholder for federal income tax purposes even if the unitholder does not receive any cash distributions from us.

Because our unitholders may be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s share of our taxable income will be taxable to the unitholder, which may require the payment of federal income taxes and, in some cases, state and local income taxes on the unitholder’s share of our taxable income, even if the unitholder receives no cash distributions from us. A unitholder may not receive cash distributions from us equal to the unitholder’s share of our taxable income or even equal to the actual tax liability that results from that income.

In the event we issue additional units or engage in certain other transactions in the future, the allocable share of nonrecourse liabilities allocated to the unitholders will be recalculated to take into account our issuance of any additional units. Any reduction in a unitholder’s share of our nonrecourse liabilities will be treated as a distribution of cash to that unitholder and will result in a corresponding tax basis reduction in a unitholder’s units. A deemed cash distribution may, under certain circumstances, result in the recognition of taxable gain by a unitholder, to the extent that the deemed cash distribution exceeds such unitholder’s tax basis in its units.


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In addition, the federal income tax liability of a unitholder could be increased if we dispose of assets or make a future offering of units and use the proceeds in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to our assets.

The taxable gain or loss on the disposition of our common units could be different than expected.

A unitholder will recognize a gain or loss for federal income tax purposes on the sale of common units equal to the difference between the amount realized and the unitholder’s tax basis in those common units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in the common units, the amount, if any, of such prior excess distributions with respect to the common units the unitholder sells will, in effect, become taxable income to a unitholder if the common units are sold at a price greater than the tax basis in those units, even if the price the unitholder receives is less than the original cost. Furthermore, a substantial portion of the amount realized on a sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder who sells common units may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-United States persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts and non-United States persons, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including individual retirement accounts and other retirement plans, may be taxable to them as “unrelated business taxable income.” Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. A unitholder that is a tax-exempt entity or a non-U.S. person should consult a tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could affect adversely the value of the common units.

Because we cannot match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could affect adversely the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.

We may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our common units each month based upon the ownership of our units as of the close of business on the last day of the preceding month, instead of on the basis of the date a particular unit is transferred. Although recently issued final Treasury regulations allow publicly traded partnerships to use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, such tax items must be prorated on a daily basis, and these regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

Unitholders may be subject to state and local taxes and return-filing requirements as a result of investing in our common units.

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property, even if the unitholder does not live in any of those jurisdictions. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions and may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign countries that impose a personal income tax or an entity level tax.


43


We determine our depreciation and cost-recovery allowances using federal income tax methods and may use methods that result in the largest deductions being taken in the early years after assets are placed in service. Some of the states in which we do business or own property may not conform to these federal depreciation methods. A successful challenge to these methods could affect adversely the amount of taxable income or loss being allocated to our unitholders for state tax purposes. It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s state tax returns. It is each unitholder’s responsibility to file all United States federal, state and local tax returns and foreign tax returns, as applicable. Our legal counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

Some of the states in which we do business or own property may require us to, or we may elect to, withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding the amount of which may be greater or less than a particular unitholder’s income tax liability to the state generally does not relieve the nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us.

The sale or exchange of 50 percent or more of our capital and profits interests during any 12-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a 12-month period. For purposes of determining whether the 50 percent threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being included in the unitholder’s taxable income for the year of termination. Our technical termination would not affect our classification as a partnership for federal income tax purposes, but instead, after our termination, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred.

The IRS has announced a publicly traded partnership technical termination relief procedure, whereby, if a publicly traded partnership that has a technical termination requests and the IRS grants special relief, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year, notwithstanding two partnership tax years resulting from the technical termination.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could affect adversely the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could affect adversely the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller, and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect

44


to those units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 2.    PROPERTIES

Natural Gas Gathering and Processing

Property - Our Natural Gas Gathering and Processing segment owns the following assets:
approximately 11,300 miles and 7,600 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 11 natural gas processing plants with approximately 965 MMcf/d of processing capacity in the Rocky Mountain region; and
approximately 15 MBbl/d of natural gas liquids fractionation capacity at various natural gas processing plants in the Mid-Continent and Rocky Mountain regions.

As discussed further in “Growth Projects” in our Natural Gas Gathering and Processing segment’s discussion in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, we also are constructing the following:
one additional natural gas processing plant in the Rocky Mountain region, which will provide approximately 80 MMcf/d of combined processing capacity; and
two de-ethanizers in the Rocky Mountain region, which will remove ethane from the natural gas stream, which we expect to be sold under a long-term contract to a customer who plans to transport the ethane on a third-party pipeline.

Utilization - The utilization rates for our natural gas processing plants were approximately 76 percent and 84 percent for 2015 and 2014, respectively. We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service.

Natural Gas Liquids

Property - Our Natural Gas Liquids segment owns the following assets:
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 4,300 miles of FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 683 MBbl/d;
approximately 4,200 miles of FERC-regulated natural gas liquids and refined petroleum products distribution pipelines with peak capacity of 993 MBbl/d;
one natural gas liquids fractionator in Oklahoma with operating capacity of approximately 210 MBbl/d, two natural gas liquids fractionators in Kansas with combined operating capacity of 280 MBbl/d and two natural gas liquids fractionators in Texas with combined operating capacity of 150 MBbl/d;
80 percent ownership interest in one natural gas liquids fractionator in Texas with our proportional share of operating capacity of approximately 128 MBbl/d;
interest in one natural gas liquids fractionator in Kansas with our 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;

45


above- and below-ground storage facilities associated with our 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.

In addition, we lease approximately 2.5 MMBbl of combined NGL storage capacity at facilities in Kansas and Texas and have access to 60 MBbl/d of natural gas liquids fractionation capacity in Texas through a fractionation service agreement.

As discussed further in “Growth Projects” in our Natural Gas Liquids segment’s discussion in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, we also have a 25 MBbl/d expansion of our Bakken NGL Pipeline and additional NGL infrastructure in the Rocky Mountain region in various stages of construction.

Utilization - The utilization rates for our various assets, including leased assets, have been impacted by ethane rejection. The utilization rates for 2015 and 2014, respectively, were as follows:
our non-FERC-regulated natural gas liquids gathering pipelines were approximately 65 percent and 62 percent;
our FERC-regulated natural gas liquids gathering pipelines were approximately 75 percent and 79 percent;
our FERC-regulated natural gas liquids distribution pipelines were approximately 43 percent and 47 percent;
our natural gas liquids fractionators were approximately 66 percent and 70 percent; and
our average contracted natural gas liquids storage volumes were approximately 66 percent and 69 percent of storage capacity.

We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service. Our fractionation utilization rate reflects approximate proportional capacity associated with our ownership interests.

Natural Gas Pipelines

Property - Our Natural Gas Pipelines segment owns the following assets:
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 55.4 Bcf of total active working natural gas storage capacity.

Our storage includes four underground natural gas storage facilities in Oklahoma, two underground natural gas storage facilities in Kansas and two underground natural gas storage facilities in Texas.

As discussed further in “Growth Projects” in our Natural Gas Pipelines segment’s discussion in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, we also are constructing or plan to construct the following:
one intrastate transmission pipeline in the Permian Basin through a 50-50 joint venture, which will provide approximately 640 MMcf/d of transportation capacity; and
one wholly owned intrastate transmission pipeline expansion in the Permian Basin, which will provide 260 MMcf/d of incremental transportation capacity.

Utilization - Our natural gas pipelines were approximately 92 percent subscribed in 2015 and 91 percent subscribed in 2014, and our natural gas storage facilities were 71 percent subscribed in 2015 and 76 percent subscribed in 2014.

ITEM 3.    LEGAL PROCEEDINGS

We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of litigation and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

ITEM 4.    MINE SAFETY DISCLOSURES

Not applicable.


46


PART II

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

MARKET INFORMATION AND HOLDERS

Our equity consists of a 2 percent general partner interest and a 98 percent limited partner interest. Our limited partner interests are represented by our common units, which are listed on the NYSE under the trading symbol “OKS,” and our Class B limited partner units. The following table sets forth the high and low closing prices of our common units for the periods indicated:
 
 
Year Ended
December 31, 2015
 
Year Ended
December 31, 2014
 
 
High
 
Low
 
High
 
Low
First Quarter
 
$
46.05

 
$
38.00

 
$
57.09

 
$
50.10

Second Quarter
 
$
43.35

 
$
34.00

 
$
58.60

 
$
53.78

Third Quarter
 
$
35.24

 
$
27.79

 
$
59.43

 
$
54.20

Fourth Quarter
 
$
34.93

 
$
22.73

 
$
56.11

 
$
38.23


At February 16, 2016, there were 507 holders of record of our 212,837,980 outstanding common units. ONEOK and its affiliates own all of the Class B units, 41,344,581 common units and the entire 2 percent general partner interest in us, which together constituted a 41.2 percent ownership interest in us at December 31, 2015.

CASH DISTRIBUTIONS

The following table sets forth the quarterly cash distribution declared and paid on each of our common and Class B units during the periods indicated:
Declared for
Quarter Ending
 
Distribution
Per Unit
 
Date Declared
 
Date Paid
December 31, 2015
 
$
0.790

 
January 21, 2016
 
February 12, 2016
September 30, 2015
 
$
0.790

 
October 21, 2015
 
November 13, 2015
June 30, 2015
 
$
0.790

 
July 23, 2015
 
August 14, 2015
March 31, 2015
 
$
0.790

 
April 16, 2015
 
May 15, 2015
December 31, 2014
 
$
0.790

 
January 15, 2015
 
February 13, 2015
September 30, 2014
 
$
0.775

 
October 23, 2014
 
November 14, 2014
June 30, 2014
 
$
0.760

 
July 25, 2014
 
August 14, 2014
March 31, 2014
 
$
0.745

 
April 18, 2014
 
May 15, 2014
December 31, 2013
 
$
0.730

 
January 16, 2014
 
February 14, 2014

CASH DISTRIBUTION POLICY

We make distributions to our partners with respect to each calendar quarter in an amount equal to 100 percent of available cash, as defined in our Partnership Agreement, within 45 days following the end of each quarter. Available cash generally consists of all cash receipts less adjustments for cash disbursements and net changes to reserves. Available cash will generally be distributed to our general partner and limited partners according to their partnership percentages of 2 percent and 98 percent, respectively. Our general partner’s percentage interest in quarterly distributions is increased after certain specified target levels are met during the quarter. Under the incentive distribution provisions, our general partner receives:
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.

Our Class B limited partner units are entitled to receive increased quarterly distributions equal to 110 percent of the distributions paid with respect to our common units. ONEOK, as the sole holder of our Class B limited partner units, has waived its right to receive the increased quarterly distributions on the Class B units. ONEOK retains the option to withdraw its waiver of increased distributions on our Class B units at any time by giving us no less than 90 days advance notice. Any such

47


withdrawal of the waiver will be effective with respect to any distribution on the Class B units declared or paid on or after the 90 days following delivery of the notice.

If our common unitholders vote at any time to remove ONEOK or its affiliates as our general partner, quarterly distributions payable on the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units, and distributions payable upon liquidation of the Class B limited partner units would increase to 123.5 percent of the distributions payable with respect to the common units.

We paid cash distributions to our general and limited partners of $1.2 billion, $1.1 billion and $909.7 million for 2015, 2014 and 2013, respectively, which included an incentive distribution to our general partner of $371.5 million, $305.0 million and $251.7 million for 2015, 2014 and 2013, respectively. Additional information about our cash distributions is included in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, under “Liquidity and Capital Resources,” and Item 13, Certain Relationships and Related Transactions, and Director Independence.

PERFORMANCE GRAPH

The following performance graph compares the performance of our common units with the S&P 500 Index and the Alerian MLP Index during the period beginning on December 31, 2010, and ending on December 31, 2015. The graph assumes a $100 investment in our common units and in each of the indices at the beginning of the period and a reinvestment of distributions/dividends paid on such investments throughout the period.

Value of $100 Investment, Assuming Reinvestment of Distributions/Dividends,
at December 31, 2010, and at the End of Every Year Through December 31, 2015,
in ONEOK Partners, L.P., the S&P 500 Index and the Alerian MLP Index


 
 
Cumulative Total Return
 
 
Years Ended December 31,
 
 
2011
 
2012
 
2013
 
2014
 
2015
 
 
 
 
 
 
 
 
 
 
 
ONEOK Partners, L.P.
 
$
153.12

 
$
149.82

 
$
154.02

 
$
122.55

 
$
101.56

Alerian MLP Index (a)
 
$
113.83

 
$
119.32

 
$
152.25

 
$
159.51

 
$
107.63

S&P 500 Index
 
$
102.08

 
$
118.39

 
$
156.70

 
$
178.10

 
$
180.56

(a) - The Alerian MLP Index measures the composite performance of the 50 most prominent energy master limited partnerships.


48


ITEM 6.    SELECTED FINANCIAL DATA

The following table sets forth our selected financial data for the periods indicated:
 
 
Years Ended December 31,
 
 
2015
 
2014
 
2013
 
2012
 
2011
 
 
(Millions of dollars, except per unit data)
Revenues
 
$
7,761.1

 
$
12,191.7

 
$
11,869.3

 
$
10,182.2

 
$
11,322.6

Net income
 
$
597.9

 
$
911.3

 
$
804.0

 
$
888.4

 
$
830.9

Net income attributable to ONEOK Partners, L.P.
 
$
589.5

 
$
910.3

 
$
803.6

 
$
888.0

 
$
830.3

Limited partners’ net income per unit
 
$
0.73

 
$
2.33

 
$
2.35

 
$
3.04

 
$
3.35

Distributions paid per common unit (a)
 
$
3.160

 
$
3.010

 
$
2.870

 
$
2.590

 
$
2.325

Total assets
 
$
14,927.6

 
$
14,600.4

 
$
12,824.2

 
$
10,927.4

 
$
8,921.7

Long-term debt, including current maturities
 
$
6,803.0

 
$
6,011.9

 
$
6,014.1

 
$
4,779.5

 
$
3,851.7

(a) - Class B unitholders received the same distribution as common unitholders.

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

The following discussion and analysis should be read in conjunction with Item 1, Business, our audited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this 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, and our Consolidated Financial Statements and Notes to Consolidated Financial Statements in this Annual Report for additional information.

Due in part to the rapid growth in crude oil and natural gas production in the United States, the global supply of crude oil and natural gas exceeded demand and led to a dramatic fall in commodity prices beginning in the fourth quarter 2014. Lower crude oil and natural gas prices persisted throughout 2015 and are expected to remain low in 2016. The production growth and decline in crude oil prices have also contributed to lower NGL product prices, as well as narrow NGL product price differentials.

WTI crude oil prices declined to an average of approximately $50.00 per barrel in 2015, compared with prices averaging approximately $93.00 per barrel in 2014. NYMEX natural gas prices also declined to an average of approximately $2.60 per MMBtu in 2015, compared with prices averaging approximately $4.30 per MMBtu in 2014. OPIS Conway propane prices averaged less than $0.41 per gallon in 2015, compared with prices averaging more than $1.10 per gallon in 2014. At December 31, 2015, prices for WTI crude oil, NYMEX natural gas and OPIS Conway propane declined to approximately $35.00 per barrel, $2.30 per MMBtu and $0.33 per gallon, respectively, and remained weak into early 2016.

We have mitigated partially our exposure to the current commodity price environment by growing our fee-based business. We have a predominantly fee-based business in our Natural Gas Liquids and Natural Gas Pipelines segments and, historically to a lesser extent, in our Natural Gas Gathering and Processing segment. In 2015, however, our Natural Gas Gathering and Processing segment restructured many POP with fee contracts associated with a significant amount of our gathered volumes to increase the fee-based component and will continue to seek opportunities to similarly restructure additional contracts in 2016. These restructured contracts favorably impacted our 2015 results, and we expect to receive the full benefit of the improved earnings from these contracts in our 2016 financial results. In the fourth quarter 2015, our Natural Gas Gathering and Processing segment’s fee revenues averaged $0.55 per MMBtu, compared with an average of $0.36 per MMBtu in 2014. As a result of these restructured contracts, we expect our Natural Gas Gathering and Processing segment’s fee-based earnings to increase significantly to more than 75 percent in 2016 and our consolidated fee-based earnings to increase to approximately 85 percent in 2016. To further mitigate the impact of lower commodity prices, we have hedged a significant portion of our Natural Gas Gathering and Processing segment’s expected equity volumes for 2016 and 2017. Our Natural Gas Liquids and Natural Gas Pipelines segments continue to provide primarily fee-based services, and many of the contracts in these segments include fixed fee, minimum volume or firm demand charge agreements that provide a minimum level of revenues regardless of commodity prices or volumetric throughput.


49


The current weakened commodity price environment, resulting from factors beyond our control, is creating challenges for our crude oil and natural gas producer customers and resulted in decreased drilling activity in 2015, compared with 2014. In the Williston Basin, the number of rigs drilling on acreage dedicated to us decreased from approximately 80 rigs in January 2015, to approximately 30 rigs in December 2015. Despite the sustained lower crude oil, natural gas and NGL prices and reduced capital spending by producers, we continue to expect demand for midstream services and infrastructure development to be driven by producers who need to connect production with end-use markets where current infrastructure is insufficient or nonexistent. Our natural gas and NGL volumes increased in 2015, particularly in the Williston Basin, as producers are focusing their drilling in the most productive areas and are using more efficient drilling and completion techniques. We expect this lower commodity price environment to continue in 2016, which will impact our net realized prices for natural gas, NGLs and condensate, as well as our financial results. If the low commodity price environment persists for a prolonged period or prices decline further, volumes across our assets may grow more slowly than in the past or decline.

Although drilling has slowed, many of our customers continue to drill new wells in the most productive areas, and improvements in drilling and completion technology are resulting in higher volumes from the wells that are completed. These new technologies, such as multi-well pads and more efficient drilling rigs, are resulting in lower drilling and completion costs, which are mitigating partially the lower commodity prices for our producer customers. In addition, new wells drilled using horizontal drilling technologies tend to produce volumes at higher initial production rates resulting generally in higher initial decline rates than conventional vertical wells; however, the decline rates flatten out over time. A significant portion of our Williston Basin gathering and processing assets are in the most productive areas, which typically produce at higher initial production rates compared with other areas, have the highest natural gas content and have slower natural gas declines than crude oil. We expect our natural gas gathered and processed volumes in the Williston Basin to continue to grow in 2016, despite expected reductions in producer drilling activity. The significant drilling activity in recent years in the Williston Basin has caused natural gas production to exceed the capacity of existing natural gas gathering and processing infrastructure, which results in the flaring of natural gas (the controlled burning of natural gas at the wellhead) by producers. We expect to capture a substantial amount of natural gas currently being flared by producers due to an additional processing plant and compression projects that were placed in service in late 2015 and projects that are expected to be completed in 2016. Additionally, we expect to benefit from production from new wells on our dedicated acreage in the Williston Basin that have been drilled previously but have not yet been completed or connected to our system by expanding our natural gas gathering and processing and natural gas liquids gathering infrastructure in the Williston Basin.

We expect ethane rejection to persist at current levels, which have exceeded 150 MBbl/d on our natural gas liquids system during 2015, until ethylene producers increase their capacity to consume additional ethane feedstock volumes through plant modifications, plant expansions and the completion of announced new world-scale ethylene production projects, which are anticipated to begin coming on line in 2017. Ethane rejection is expected to continue to have a significant impact on our financial results into 2017.

Beginning in June 2015, our Natural Gas Gathering and Processing segment reduced its level of ethane rejection in the Williston Basin to alleviate downstream NGL product specification issues, which offsets partially the financial impact of ethane rejection. We expect this decreased level of ethane rejection to continue throughout 2016. In addition, our Natural Gas Liquids segment’s integrated assets enable us to mitigate partially this impact through minimum volume commitments, contract modifications that vary fees for ethane and other NGL products, and our ability to utilize the transportation capacity made available due to ethane rejection to capture additional NGL location price differentials, when they exist, in our optimization activities.

Growth Projects - In 2015, crude oil and natural gas producers continued to drill for crude oil and NGL-rich natural gas in many regions where we have operations, including in the Bakken Shale and Three Forks formations in the Williston Basin; in the Cana-Woodford Shale, Woodford Shale, Springer Shale, Stack and SCOOP areas in the Mid-Continent region; and in the Permian Basin. In response to this continued production of crude oil, natural gas and NGLs, and higher demand for NGL products from the petrochemical industry, we have completed growth projects and acquisitions in these regions. In addition, our current projects are expected to expand our natural gas gathering and processing and natural gas liquids gathering infrastructure in the Williston Basin to capture natural gas currently being flared by producers. Through our Roadrunner joint venture, we are constructing a pipeline to transport natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas. The Roadrunner pipeline will connect with our existing natural gas pipeline and storage infrastructure in Texas and, together with our WesTex intrastate natural gas transmission pipeline expansion project, is expected to create a platform for future opportunities to deliver natural gas supply to Mexico. The execution of these capital investments aligns with our strategy to generate consistent growth and sustainable earnings. Our contractual commitments from crude oil and natural gas producers, natural gas processors and electric generators are expected to provide incremental cash flows and long-term fee-based earnings.


50


While reduced crude oil and natural gas producer drilling activity is slowing supply growth, we expect to complete our previously announced projects to meet crude oil and natural gas producers’ demand for our gathering, processing, fractionation and transportation services. We have suspended capital expenditures for certain natural gas processing plants and related infrastructure to align with the needs of our customers. We could resume our suspended capital-growth projects when market conditions improve and our customers’ needs change. In 2016, we expect lower capital spending, compared with spending levels from 2013 through 2015, due to the current commodity price environment and our alignment of capital-growth projects with the needs of our customers. If the current commodity price environment persists for a prolonged period, it may further impact the timing or demand for additional infrastructure projects or growth opportunities in the future.

WesTex Transmission Pipeline Expansion - In July 2015, we announced plans to invest $70 million to $100 million to expand our WesTex intrastate natural gas pipeline system in the Permian Basin in our Natural Gas Pipelines segment. WesTex, which had qualifying open season bids in excess of 500 MMcf/d, plans to utilize 240 MMcf/d of existing capacity and create additional capacity by expanding its system by 260 MMcf/d by the first quarter 2017. This expansion project is supported by firm demand charge transportation agreements and is complementary to our recently announced Roadrunner joint venture pipeline project discussed below.

See additional discussion of our other growth projects in the “Financial Results and Operating Information” section in our Natural Gas Gathering and Processing, Natural Gas Liquids and Natural Gas Pipelines segments.

Roadrunner - In March 2015, we entered into a 50-50 joint venture with a subsidiary of Fermaca Infrastructure B.V. (Fermaca), a Mexico City-based natural gas infrastructure company, to construct a pipeline to transport natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas. The pipeline will connect with our existing natural gas pipeline and storage infrastructure in Texas. These integrated assets are also expected to provide markets in Mexico access to upstream supply basins in West Texas and the Mid-Continent region, which adds location and price diversity to their supply mix and supports the plan of Mexico’s national electric utility, Comisión Federal de Electricidad, to replace fuel oil-based power plants with natural gas-fueled power plants, which are more economical and produce fewer GHG emissions. The estimated total cost of the project is approximately $430 million to $480 million. We contributed approximately $30 million to Roadrunner in 2015, and we expect to contribute approximately $50 million to Roadrunner during 2016.

Roadrunner has all permits needed to complete construction on Phase I and all permits needed to begin construction on Phase II. Construction on both Phase I and Phase II is ongoing and we expect Phase I to be completed in the first quarter 2016.

Roadrunner entered into a $230 million senior secured credit facility for the construction and operation of the pipeline. The senior secured credit facility expires seven years after the Roadrunner in-service date of Phase II, which is expected to be completed in the first quarter 2017. In addition, Roadrunner executed interest-rate swaps to hedge the variability of its interest payments during the term of the credit facility. Roadrunner’s credit facility is nonrecourse to us, and we do not guarantee Roadrunner’s debts or obligations under the credit facility.

See additional discussion in the “Financial Results and Operating Information” section in our Natural Gas Pipelines segment.

Impairment Charges - In the fourth quarter 2015, we recorded $264.3 million of noncash impairment charges, primarily related to our long-lived assets and equity investments in the dry natural gas area of the Powder River Basin.

Cash Distributions - During 2015, we paid cash distributions totaling $3.16 per unit, an increase of approximately 5 percent over the $3.01 per unit paid during 2014. In January 2016, our general partner declared a cash distribution of $0.79 per unit ($3.16 per unit on an annualized basis) for the fourth quarter 2015.

Debt Issuances - In January 2016, we entered into the $1.0 billion senior unsecured Term Loan Agreement with a syndicate of banks that matures in January 2019. Proceeds from the Term Loan Agreement effectively refinance our 2016 debt maturities.

In March 2015, we completed an underwritten public offering of $800 million of senior notes, generating net proceeds of approximately $792.3 million. We used the proceeds to repay amounts outstanding under our commercial paper program and for general partnership purposes.

Equity Issuances - In August 2015, we completed a private placement of 21.5 million common units at a price of $30.17 per unit with ONEOK. Additionally, we completed a concurrent sale of approximately 3.3 million common units at a price of $30.17 per unit to funds managed by Kayne Anderson Capital Advisors in a registered direct offering, which were issued through our existing “at-the-market” equity program. The combined offerings generated net cash proceeds of approximately $749 million. In conjunction with these issuances, ONEOK Partners GP contributed approximately $15.3 million in order to

51


maintain its 2 percent general partner interest in us. We used the proceeds for general partnership purposes, including capital expenditures and repayment of commercial paper borrowings.

During 2015, we sold 10.5 million common units through our “at-the-market” equity program, including the units sold to funds managed by Kayne Anderson Capital Advisors in the offering discussed above. The net proceeds, including ONEOK Partners GP’s contribution to maintain its 2 percent general partner interest in us, were approximately $381.6 million, which were used for general partnership purposes, including repayment of commercial paper borrowings.

As a result of these transactions, ONEOK’s aggregate ownership interest in us increased to 41.2 percent at December 31, 2015, compared with 37.8 percent at December 31, 2014.

FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

Selected Financial Results - The following table sets forth certain selected consolidated financial results for the periods indicated:
 
 
 
 
 
 
 
 
Variances
 
Variances
 
 
Years Ended December 31,
 
2015 vs. 2014
 
2014 vs. 2013
Financial Results
 
2015
 
2014
 
2013
 
Increase (Decrease)
 
Increase (Decrease)
 
 
(Millions of dollars)
Revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity sales
 
$
6,098.3

 
$
10,725.0

 
$
10,549.2

 
$
(4,626.7
)
 
(43
)%
 
$
175.8

 
2
 %
Services
 
1,662.8

 
1,466.7

 
1,320.1

 
196.1

 
13
 %
 
146.6

 
11
 %
Total revenues
 
7,761.1

 
12,191.7

 
11,869.3

 
(4,430.6
)
 
(36
)%
 
322.4

 
3
 %
Cost of sales and fuel (exclusive of items shown separately below)
 
5,641.1

 
10,088.6

 
10,222.2

 
(4,447.5
)
 
(44
)%
 
(133.6
)
 
(1
)%
Operating costs
 
692.1

 
669.7

 
521.6

 
22.4

 
3
 %
 
148.1

 
28
 %
Depreciation and amortization
 
352.2

 
291.2

 
236.7

 
61.0

 
21
 %
 
54.5

 
23
 %
Impairment of long-lived assets
 
83.7

 

 

 
83.7

 
*

 

 
 %
Gain (loss) on sale of assets
 
6.1

 
6.6

 
11.9

 
(0.5
)
 
(8
)%
 
(5.3
)
 
(45
)%
Operating income
 
$
998.1

 
$
1,148.8

 
$
900.7

 
$
(150.7
)
 
(13
)%
 
$
248.1

 
28
 %
Equity in net earnings from investments
 
$
125.3

 
$
117.4

 
$
110.5

 
$
7.9

 
7
 %
 
$
6.9

 
6
 %
Impairment of equity investments
 
$
(180.6
)
 
$
(76.4
)
 
$

 
$
104.2

 
*

 
$
76.4

 
*

Interest expense
 
$
(338.9
)
 
$
(281.9
)
 
$
(236.7
)
 
$
57.0

 
20
 %
 
$
45.2

 
19
 %
Capital expenditures
 
$
1,186.1

 
$
1,746.0

 
$
1,939.3

 
$
(559.9
)
 
(32
)%
 
$
(193.3
)
 
(10
)%
Cash paid for acquisitions, net of cash received
 
$

 
$
814.9

 
$
394.9

 
$
(814.9
)
 
(100
)%
 
$
420.0

 
*

* Percentage change is greater than 100 percent or is not meaningful.

Due to the nature of our contracts, changes in commodity prices and volumes affect both commodity sales and cost of sales and fuel in our Consolidated Statements of Income and therefore the impact is largely offset between the two line items. As a result, we consider operating income provided by revenues less cost of sales and fuel meaningful and necessary to understand our results of operations.

2015 vs. 2014 - Services revenues increased for 2015, compared with 2014, due primarily to higher natural gas and NGL volumes from our recently completed capital projects and acquisitions, in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and higher fees resulting from contract restructuring in our Natural Gas Gathering and Processing segment.

Commodity sales revenues and costs of sales and fuel decreased for 2015, compared with 2014, due to the sharp decline in commodity prices that began in the fourth quarter 2014 and continued throughout 2015 and higher propane and natural gas prices, as well as wider NGL location and product price differentials experienced in the first quarter 2014 as a result of unusually high weather-related seasonal demand. The impact from the price decrease was offset partially by higher gathered and processed volumes in our Natural Gas Gathering and Processing segment and higher NGL volumes transported on gathering lines and fractionated in our Natural Gas Liquids segment in 2015, compared with 2014.


52


Operating costs and depreciation and amortization expense increased for 2015, compared with 2014, due primarily to the growth of our operations related to the completed capital projects, including acquisitions, in our Natural Gas Gathering and Processing and Natural Gas Liquids segments. This increase was offset partially by decreased operating costs due to lower rates charged by service providers.

We recorded $264.3 million and $76.4 million of noncash impairment charges, primarily related to our long-lived assets and equity investments in the dry natural gas area of the Powder River Basin in 2015 and 2014, respectively.

Equity in net earnings from investments increased for 2015, compared with 2014, due primarily to higher volumes in 2015 delivered to Overland Pass Pipeline from our Bakken NGL Pipeline in our Natural Gas Liquids segment.

Interest expense increased for 2015, compared with 2014, primarily as a result of higher interest costs incurred associated with our issuance of $800 million of senior notes in March 2015, higher interest rates on short-term borrowings and lower capitalized interest due to capital-growth projects completed and placed in service in 2014.

Capital expenditures decreased for 2015, compared with 2014, due to the completion of several large capital-growth projects in 2014, suspension of several projects and the timing of expenditures in 2015 for our capital-growth projects. Cash paid for acquisitions in 2014 relates primarily to the West Texas LPG acquisition for approximately $800 million.

Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.

2014 vs. 2013 - Revenues less cost of sales and fuel for 2014, compared with 2013, increased due primarily to higher volumes across our systems. Our new natural gas processing plants in the Williston Basin and Mid-Continent region resulted in increased natural gas volumes gathered, processed and sold in our Natural Gas Gathering and Processing segment and, combined with third-party plant connections, increased NGL volumes transported in our Natural Gas Liquids segment’s exchange-services business. Our optimization, marketing, isomerization and differentials-based businesses benefited from wider realized NGL product price differentials in 2014, compared with 2013, primarily related to increased weather-related seasonal demand for propane during the first quarter 2014 and wider realized NGL product price differentials between normal butane and iso-butane. Our Natural Gas Pipelines segment also experienced higher transportation revenues, primarily from increased rates and higher contracted capacity and higher storage revenues from park-and-loan activity. These increases were offset partially by the impact of ethane rejection in our Natural Gas Liquids segment and lower contracted storage capacity in our Natural Gas Pipelines segment.

Operating costs and depreciation and amortization expense increased for 2014, compared with 2013, due primarily to the growth of our operations related to the completed capital projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

In 2014, we recorded $76.4 million of noncash impairment charges related to our equity investment in Bighorn Gas Gathering in our Natural Gas Gathering and Processing segment.

Equity in net earnings from investments increased for 2014, compared with 2013, due primarily to higher volumes in 2014 delivered to Overland Pass Pipeline from our Bakken NGL Pipeline in our Natural Gas Liquids segment.

Interest expense increased for 2014, compared with 2013, primarily as a result of higher interest costs incurred associated with a full year of interest costs on our issuance of $1.25 billion of senior notes in September 2013.

Capital expenditures decreased for 2014, compared with 2013, due primarily to the timing of expenditures related to growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments. In 2014, we also completed the West Texas LPG acquisition for approximately $800 million, compared with our 2013 Sage Creek and Maysville acquisitions totaling approximately $395 million.

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

Growth Projects - Our Natural Gas Gathering and Processing segment is investing in growth projects in NGL-rich areas in the Williston Basin, Stack, SCOOP, Cana-Woodford Shale, Woodford Shale, Springer Shale and the Powder River Basin areas that

53


we expect will enable us to meet the needs of crude oil and natural gas producers in those areas. Nearly all of the new natural gas production is from horizontally drilled wells in nonconventional resource areas. These wells tend to produce volumes at higher initial production rates resulting generally in higher initial decline rates than conventional vertical wells; however, the decline rates flatten out over time. These wells are expected to have long productive lives.

In 2014 and 2015, we completed the following projects:
Completed Projects
Location
Capacity
Approximate
Costs (a)
Completion Date
 
 
 
(In millions)
 
Rocky Mountain Region
 
 
 
 
Garden Creek II processing plant and infrastructure
Williston Basin
100 MMcf/d
$310
August 2014
Garden Creek III processing plant and infrastructure
Williston Basin
100 MMcf/d
$310
October 2014
Lonesome Creek processing plant and infrastructure
Williston Basin
200 MMcf/d
$580 - $620
November 2015
Sage Creek infrastructure
Powder River Basin
Various
$35
December 2015
Natural gas compression
Williston Basin
100 MMcf/d
$70 - $80
December 2015
Mid-Continent Region
 
 
 
 
Canadian Valley processing plant and infrastructure
Cana-Woodford Shale
200 MMcf/d
$255
March 2014
(a) Excludes AFUDC.

We have the following natural gas processing plants and related infrastructure in various stages of construction:
Projects in Progress
Location
Capacity
Approximate
Costs (a)
Expected
Completion Date
 
 
 
(In millions)
 
Rocky Mountain Region
 
 
 
 
Stateline de-ethanizers
Williston Basin
26 MBbl/d
$60 - $80
Third quarter 2016
Bear Creek processing plant and infrastructure
Williston Basin
80 MMcf/d
$230 - $330
Third quarter 2016
Bronco processing plant and infrastructure
Powder River Basin
50 MMcf/d
$130 - $200
Suspended
Demicks Lake processing plant and infrastructure
Williston Basin
200 MMcf/d
$475 - $670
Suspended
Mid-Continent Region
 
 
 
 
Knox processing plant and infrastructure
SCOOP
200 MMcf/d
$240 - $470
Suspended
Total
 
 
$1,135 - $1,750
 
(a) Excludes AFUDC.

As a result of reductions in crude oil and natural gas drilling by producers due to the decline in crude oil, natural gas and NGL prices and our expectation of slower supply growth or declines, we suspended capital expenditures for certain natural gas processing plants and field infrastructure. We could resume our suspended capital-growth projects when market conditions improve and our customers’ needs change. If the current commodity price environment persists for a prolonged period, it may further impact the timing or demand for these projects and additional infrastructure projects or growth opportunities in the future.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.


54


Selected Financial Results - Our Natural Gas Gathering and Processing segment’s financial results for the year ended December 31, 2015, reflect the benefits from the completed projects in the table above.
The following table sets forth certain selected financial results for our Natural Gas Gathering and Processing segment for the periods indicated:
 
 
 
 
 
 
 
 
Variances
 
Variances
 
 
Years Ended December 31,
 
2015 vs. 2014
 
2014 vs. 2013
Financial Results
 
2015
 
2014
 
2013
 
Increase (Decrease)
 
Increase (Decrease)
 
 
(Millions of dollars)
NGL sales
 
$
554.3

 
$
1,434.4

 
$
1,095.5

 
$
(880.1
)
 
(61
)%
 
$
338.9

 
31
 %
Condensate sales
 
55.1

 
110.8

 
113.2

 
(55.7
)
 
(50
)%
 
(2.4
)
 
(2
)%
Residue natural gas sales
 
839.5

 
1,140.5

 
620.5

 
(301.0
)
 
(26
)%
 
520.0

 
84
 %
Gathering, compression, dehydration and
processing fees and other revenue
 
388.2

 
281.9

 
222.3

 
106.3

 
38
 %
 
59.6

 
27
 %
Cost of sales and fuel (exclusive of items shown separately below)
 
1,265.6

 
2,305.7

 
1,550.9

 
(1,040.1
)
 
(45
)%
 
754.8

 
49
 %
Operating costs
 
272.4

 
257.7

 
193.3

 
14.7

 
6
 %
 
64.4

 
33
 %
Depreciation and amortization
 
150.0

 
123.8

 
103.9

 
26.2

 
21
 %
 
19.9

 
19
 %
Impairment of long-lived assets
 
73.7

 

 

 
73.7

 
*

 

 
 %
Gain (loss) on sale of assets
 
2.8

 
0.2

 
0.4

 
2.6

 
*

 
(0.2
)
 
(50
)%
Operating income
 
$
78.2

 
$
280.6

 
$
203.8

 
$
(202.4
)
 
(72
)%
 
$
76.8

 
38
 %
Equity in net earnings from investments
 
$
17.9

 
$
20.3

 
$
23.5

 
$
(2.4
)
 
(12
)%
 
$
(3.2
)
 
(14
)%
Impairment of equity investments
 
$
(180.6
)
 
$
(76.4
)
 
$

 
$
104.2

 
*

 
$
76.4

 
*

Capital expenditures
 
$
887.9

 
$
898.9

 
$
774.4

 
$
(11.0
)
 
(1
)%
 
$
124.5

 
16
 %
Cash paid for acquisitions
 
$

 
$

 
$
241.9

 
$

 
 %
 
$
(241.9
)
 
(100
)%
* Percentage change is greater than 100 percent or is not meaningful.

Commodity prices declined sharply in the fourth quarter 2014 and continued to decline throughout 2015. We expect lower commodity prices to continue throughout 2016. Therefore, we also expect crude oil, natural gas and NGL supply growth to continue to slow. As crude oil and natural gas exploration and production capital investment has decreased due to market conditions, crude oil and natural gas producers are focusing their drilling activities in the most productive areas that are most economical to develop and have higher production volumes, which offsets partially the reduction in drilling activity. The lower commodity price environment had a significant impact on our Natural Gas Gathering and Processing segment’s financial results in 2015, compared with 2014, but was mitigated partially by restructured contracts primarily in the fourth quarter 2015.

2015 vs. 2014 - Operating income provided by revenues less cost of sales and fuel decreased primarily as a result of the following:
a decrease of $209.7 million due primarily to lower net realized NGL, natural gas and condensate prices; and
a decrease of $10.4 million due primarily to decreased ethane rejection to maintain downstream NGL product specifications; offset partially by
an increase of $91.6 million due primarily to restructured contracts resulting in higher average fee rates and a lower percentage of proceeds retained from the sale of commodities under our POP with fee contracts; and
an increase of $38.1 million due primarily to natural gas volume growth in the Williston Basin, offset partially by unplanned operational outages in the Williston Basin and decreased natural gas volumes in the Cana-Woodford Shale.

Operating costs increased due primarily to the growth of our operations and reflect the following:
an increase of $13.8 million in higher outside service expenses due primarily to the completion of our growth projects;
an increase of $10.5 million in employee-related costs due to higher labor and employee benefit costs resulting from the completion of our growth projects; and
an increase of $3.1 million due to higher ad valorem taxes resulting from the completion of our growth projects; offset partially by
a decrease of $12.7 million in materials and supplies due primarily to lower chemical costs.

Depreciation and amortization expense increased due to the completion of growth projects.


55


We recorded $254.3 million and $76.4 million of noncash impairment charges primarily related to our long-lived assets and equity investments in the dry natural gas area of the Powder River Basin in 2015 and 2014, respectively. See additional discussion in “Impairment Charges” below.

Capital expenditures decreased due primarily to the timing of our growth projects discussed above.

See “Capital Expenditures” in “Liquidity and Capital Resources” for additional detail of our projected capital expenditures.

2014 vs. 2013 - Operating income provided by revenues less cost of sales and fuel increased primarily as a result of the following:
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 higher average fee rates and a lower percentage of proceeds retained from the sale of commodities under our POP with fee contracts; offset partially by
a decrease of $6.4 million due to a condensate contract settlement in 2013.

Operating costs increased due primarily to the growth of our operations and reflect the following:
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.

Depreciation and amortization expense increased due to the completion of growth projects and acquisitions.

In 2014, we recorded $76.4 million of noncash impairment charges related to our equity investment in Bighorn Gas Gathering.

Capital expenditures increased due primarily to the timing of our growth projects discussed above.

Selected Operating Information - The following tables set forth selected operating information for our Natural Gas Gathering and Processing segment for the periods indicated:
 
 
Years Ended December 31,
Operating Information (a)
 
2015
 
2014
 
2013
Natural gas gathered (BBtu/d)
 
1,932

 
1,733

 
1,347

Natural gas processed (BBtu/d) (b)
 
1,687

 
1,534

 
1,094

NGL sales (MBbl/d)
 
129

 
104

 
79

Residue natural gas sales (BBtu/d)
 
853

 
714

 
497

Realized composite NGL net sales price ($/gallon) (c) (d)
 
$
0.34

 
$
0.93

 
$
0.87

Realized condensate net sales price ($/Bbl) (c) (e)
 
$
37.81

 
$
76.43

 
$
86.00

Realized residue natural gas net sales price ($/MMBtu) (c) (e)
 
$
3.64

 
$
3.92

 
$
3.53

Average fee rate ($MMBtu)
 
$
0.44

 
$
0.36

 
$
0.34

(a) - Includes volumes for consolidated entities only.
(b) - Includes volumes at company-owned and third-party facilities.
(c) - Includes the impact of hedging activities on our equity volumes.
(d) - Net of transportation and fractionation costs.
(e) - Net of transportation costs.

Natural gas gathered and processed, NGL sales and residue natural gas sales increased in 2015, compared with 2014, due to the completion of growth projects in the Williston Basin, offset partially by unplanned outages in the Williston Basin during the third quarter and natural gas volume declines in the Cana-Woodford Shale. In 2016, we expect our average natural gas gathered volumes to increase in the Cana-Woodford Shale as a result of wells completed in late 2015. Natural gas gathered and processed, NGL sales and residue natural gas sales increased in 2014, compared with 2013, due to the completion of growth projects in the Williston Basin and the Mid-Continent areas, offset partially by natural declines in the Powder River Basin.

56



The quantity and composition of NGLs and natural gas have varied as new plants were placed in service and to ensure natural gas and natural gas liquids pipeline specifications were met. Beginning in June 2015, we reduced the level of ethane rejection in the Rocky Mountain region to address downstream NGL product specifications. In 2016, we expect additional volumes from our Lonesome Creek and Bear Creek processing plants in the Williston Basin to further reduce the level of ethane rejection. We expect the decreased level of ethane rejection to continue throughout 2016.
 
 
Years Ended December 31,
Equity Volume Information (a)
 
2015
 
2014
 
2013
 
 
 
 
 
 
 
NGL sales (MBbl/d)
 
20.9

 
16.5

 
14.4

Condensate sales (MBbl/d)
 
2.8

 
3.1

 
2.4

Residue natural gas sales (BBtu/d)
 
136.2

 
118.2

 
71.7

(a) - Includes volumes for consolidated entities only.

Commodity Price Risk - Our Natural Gas Gathering and Processing segment is exposed to commodity price risk as a result of receiving commodities as a portion of our compensation for our services. See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Impairment Charges - Crude oil and natural gas producers have primarily focused their development efforts on crude oil and NGL-rich supply basins rather than in areas with dry natural gas production, such as the coal-bed methane production areas in the Powder River Basin. The reduced development activities and production declines in the dry natural gas area of the Powder River Basin have resulted in lower natural gas volumes available to be gathered. Due to the continued and greater than expected decline in volumes gathered in the dry natural gas area of the Powder River Basin, we evaluated our long-lived assets and equity investments in this area and determined that we will cease operations of our wholly owned coal-bed methane natural gas gathering system in 2016. This resulted in a $63.5 million noncash impairment charge to our long-lived assets in the fourth quarter 2015. Bighorn Gas Gathering, in which we own a 49 percent equity interest, and Fort Union Gas Gathering, in which we own a 37 percent equity interest, are both partially supplied with volumes from our wholly owned coal-bed methane natural gas gathering system. We also own a 35 percent equity interest in Lost Creek Gathering Company, which also is located in a dry natural gas area. We reviewed our Bighorn Gas Gathering, Fort Union Gas Gathering and Lost Creek Gathering Company equity investments and recorded noncash impairment charges of $180.6 million in the fourth quarter 2015. The remaining net book value of our equity investments in this dry natural gas area is $35.0 million.

In the fourth quarter 2015, we also recorded a noncash impairment charge of approximately $10.2 million related to a previously idled asset, as our expectation for future use of the asset changed.

During 2014, Bighorn Gas Gathering recorded an impairment of its underlying assets when the operator determined that the volume decline would be sustained for the foreseeable future. As a result, we reviewed our equity investment in Bighorn Gas Gathering for impairment and recorded noncash impairment charges of $76.4 million in 2014 related to Bighorn Gas Gathering.

Natural Gas Liquids

Growth Projects - Our growth strategy in our Natural Gas Liquids segment is focused around the crude oil and NGL-rich natural gas drilling activity in shale and other nonconventional resource areas from the Rocky Mountain region through the Mid-Continent region into Texas and New Mexico. Crude oil, natural gas and NGL production from this activity; higher petrochemical industry demand for NGL products; and increased exports have resulted in our making additional capital investments to expand our infrastructure to bring these commodities from supply basins to market. Expansion of the petrochemical industry in the United States is expected to increase ethane demand significantly beginning in 2017, and international demand for NGLs, particularly propane, also is increasing and is expected to continue to do so in the future.

Our Natural Gas Liquids segment invests in NGL-related projects to accommodate the transportation, fractionation and storage of NGL supply from shale and other resource development areas across our asset base and alleviate expected infrastructure constraints between the Mid-Continent and Gulf Coast market centers to meet increasing petrochemical industry and NGL export demand in the Gulf Coast.


57


We completed the following growth projects in this segment in 2014 and 2015:
Completed Projects
Location
Capacity
Approximate Costs (a)
Completion Date
 
 
 
(In millions)
 
Ethane/Propane Splitter
Gulf Coast
40 MBbl/d
$46
March 2014
Sterling III Pipeline and reconfigure Sterling I and II
Mid-Continent Region
193 MBbl/d
$808
March 2014
Bakken NGL Pipeline expansion - Phase I
Rocky Mountain Region
75 MBbl/d
$90
September 2014
Niobrara NGL Lateral
Powder River Basin
90 miles
$65
September 2014
West Texas LPG (b)
Permian Basin
2,600 miles
$800
November 2014
MB-3 Fractionator
Gulf Coast
75 MBbl/d
$530
December 2014
NGL Pipeline and Hutchinson Fractionator infrastructure
Mid-Continent Region
95 miles
$120
April 2015
(a) Excludes AFUDC.
(b) Acquisition.

We have the following projects in various stages of construction:
Projects in Progress
Location
Capacity
Approximate Costs (a)
Expected
Completion Date
 
 
 
(In millions)
 
Bear Creek NGL infrastructure
Williston Basin
40 miles
$35-$45
Third quarter 2016
Bakken NGL Pipeline expansion - Phase II
Rocky Mountain Region
25 MBbl/d
$100
Third quarter 2018
Bronco NGL infrastructure
Powder River Basin
65 miles
$45-$60
Suspended
Demicks Lake NGL infrastructure
Williston Basin
12 miles
$10-$15
Suspended
Total
 
 
$190-$220
 
(a) Excludes AFUDC.

As a result of reductions in crude oil and natural gas drilling activities and our expectation of continued slower supply growth or declines due to the lower crude oil, natural gas and NGL prices, we have suspended capital expenditures for certain natural gas liquids infrastructure projects related to planned natural gas processing plants. We could resume our suspended capital-growth projects when market conditions improve and our customers’ needs change. If the current commodity price environment persists for a prolonged period, it may further impact the timing or demand for these projects and additional infrastructure projects or growth opportunities in the future.

For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.


58


Selected Financial Results - Our Natural Gas Liquids segment’s financial results for the year ended December 31, 2015, reflect the benefits from the completed growth projects in the table above.

The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids segment for the periods indicated:
 
 
 
 
 
 
 
 
Variances
 
Variances
 
 
Years Ended December 31,
 
2015 vs. 2014
 
2014 vs. 2013
Financial Results
 
2015
 
2014
 
2013
 
Increase (Decrease)
 
Increase (Decrease)
 
 
(Millions of dollars)
NGL and condensate sales
 
$
5,200.8

 
$
9,462.4

 
$
9,857.7

 
$
(4,261.6
)
 
(45
)%
 
$
(395.3
)
 
(4
)%
Exchange service and storage revenues
 
1,199.7

 
988.8

 
839.3

 
210.9

 
21
 %
 
149.5

 
18
 %
Transportation revenues
 
179.2

 
94.2

 
81.0

 
85.0

 
90
 %
 
13.2

 
16
 %
Cost of sales and fuel (exclusive of items shown separately below)
 
5,328.3

 
9,435.3

 
9,908.1

 
(4,107.0
)
 
(44
)%
 
(472.8
)
 
(5
)%
Operating costs
 
314.5

 
296.4

 
236.6

 
18.1

 
6
 %
 
59.8

 
25
 %
Depreciation and amortization
 
158.7

 
124.1

 
89.2

 
34.6

 
28
 %
 
34.9

 
39
 %
Impairment of long-lived assets
 
10.0

 

 

 
10.0

 
*

 

 
 %
Gain (loss) on sale of assets
 
(0.9
)
 
(0.6
)
 
0.8

 
(0.3
)
 
50
 %
 
(1.4
)
 
*

Operating income
 
$
767.3

 
$
689.0

 
$
544.9

 
$
78.3

 
11
 %
 
$
144.1