10-K 1 form_10-k.htm OKS FORM 10-K form_10-k.htm
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, 2011.
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 definition 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, 2011, was $5.1 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 14, 2012    
Common units    130,827,354 units 
Class B units     72,988,252 units 
DOCUMENTS INCORPORATED BY REFERENCE: None.
ONEOK PARTNERS, L.P.
2011 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.
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, 2011
ASU
Accounting Standards Update
Bbl
Barrels, 1 barrel is equivalent to 42 United States gallons
Bbl/d
Barrels per day
BBtu/d
Billion British thermal units per day
Bcf
Billion cubic feet
Bcf/d
Billion cubic feet per day
Bighorn Gas Gathering
Bighorn Gas Gathering, L.L.C.
Btu(s)
British thermal units, a measure of the amount of heat required to raise the
     temperature of one pound of water one degree Fahrenheit
Bushton Plant
Bushton Gas Processing Plant
CFTC
Commodities Futures Trading Commission
Clean Air Act
Federal Clean Air Act, as amended
Clean Water Act
Federal Water Pollution Control Act, as amended
Dodd-Frank Act
Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
EBITDA
Earnings before interest expense, income taxes, depreciation and amortization
EBITDAR
Earnings before interest expense, income taxes, depreciation and amortization,
     and rent expense
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
Fort Union Gas Gathering
Fort Union Gas Gathering, L.L.C.
GAAP
Accounting principles generally accepted in the United States of America
Guardian Pipeline
Guardian Pipeline, L.L.C.
Heartland
Heartland Pipeline Company
Intermediate Partnership
ONEOK Partners Intermediate Limited Partnership, a wholly owned subsidiary
     of ONEOK Partners, L.P.
IRS
Internal Revenue Service
KCC
Kansas Corporation Commission
KDHE
Kansas Department of Health and Environment
LIBOR
London Interbank Offered Rate
MBbl
Thousand barrels
MBbl/d
Thousand barrels per day
MDth/d
Thousand dekatherms per day
Midwestern Gas Transmission
Midwestern Gas Transmission Company
MMBbl
Million barrels
MMBtu
Million British thermal units
MMBtu/d
Million British thermal units per day
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
NBP Services
NBP Services, LLC, a wholly owned subsidiary of ONEOK
NGL products
Marketable natural gas liquid purity products, such as ethane, ethane/propane
     mix, propane, iso-butane, normal butane and natural gasoline
NGL(s)
Natural gas liquid(s)
Northern Border Pipeline
Northern Border Pipeline Company
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
OBPI
ONEOK Bushton Processing Inc.
OCC
Oklahoma Corporation Commission
OKTex Pipeline
OkTex Pipeline Company, L.L.C.
ONEOK
ONEOK, Inc.
ONEOK Partners GP
ONEOK Partners GP, L.L.C., a wholly owned subsidiary of ONEOK and our
     sole general partner
OPIS
Oil Price Information Service
OSHA
Occupational Safety and Health Administration
Overland Pass Pipeline Company
Overland Pass Pipeline Company LLC
Partnership Agreement
Third Amended and Restated Agreement of Limited Partnership of ONEOK
     Partners, L.P., as amended
Partnership Credit Agreement
The Partnership’s $1.0 billion amended and restated revolving credit agreement
     dated March 30, 2007
Partnership 2011 Credit Agreement
The Partnership’s five-year, $1.2 billion Revolving Credit Agreement dated
     August 1, 2011
POP
Percent of Proceeds
Quarterly Report(s)
Quarterly Report(s) on Form 10-Q
RRC
Railroad Commission of Texas
S&P
Standard & Poor’s Rating Services
SEC
Securities and Exchange Commission
Securities Act
Securities Act of 1933, as amended
TransCanada
TransCanada Corporation
Viking Gas Transmission
Viking Gas Transmission Company
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 Operation, and “Forward-Looking Statements,” in this Annual Report.
ITEM 1.
 BUSINESS
 
GENERAL

ONEOK Partners, L.P. is a publicly traded Delaware master limited partnership 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 and Rocky Mountain regions with key market centers.

EXECUTIVE SUMMARY

North American natural gas production continues to increase at a faster rate than demand, primarily as a result of increased production from nonconventional resource areas, such as shale plays.  Because of the relatively higher market prices of crude oil and NGLs, drilling activity is especially robust in shale plays with crude oil and NGL-rich natural gas production.  As a result, we expect producers to focus development efforts on crude oil and NGL-rich supply basins rather than areas with dry natural gas production.  We expect inter-regional opportunities for midstream infrastructure development driven by producers who need to connect emerging production with end-use markets where current infrastructure is insufficient or nonexistent.

In 2011, producers continued to drill aggressively in a number of NGL-rich resource plays in the Mid-Continent and Rocky Mountain regions, creating a need for additional infrastructure to bring this new supply to market.  The resulting increase in natural gas supply has caused lower natural gas prices, less volatility and narrower natural gas location and seasonal price differentials in the markets we serve.

Additionally, we have seen strong ethane demand from the petrochemical sector in the Gulf Coast, due to the price advantage ethane has over other feedstocks.  Consequently, NGL pipeline capacity between the Conway, Kansas, and Mont Belvieu, Texas, market centers is constrained and contributes to wider location price differentials between those markets.  The natural gas supply growth has also increased NGL supply in the Mid-Continent, coupled with increased demand in the Gulf Coast, resulting in decreased NGL prices in the Mid-Continent market center at Conway, Kansas, relative to prices in the Gulf Coast market center at Mont Belvieu, Texas.

Additional fractionation and pipeline capacity is needed to accommodate the growing NGL supply and demand, as well as new infrastructure to gather, process and transport growing natural gas production from both new and existing resource plays.  In response to this increased production and demand for NGL products, we are investing approximately $2.7 billion to $3.3 billion in new capital projects to meet the needs of oil and natural gas producers in the Bakken Shale, the Cana-Woodford Shale and the Granite Wash areas, and for additional NGL infrastructure in the Mid-Continent and Gulf Coast areas that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand.  When completed, we expect these projects to provide additional earnings and cash flows.

During 2011, we paid cash distributions of $2.325 per unit, an increase of approximately 4.3 percent over the $2.23 per unit paid during 2010.  In January 2012, our general partner declared a cash distribution of $0.61 per unit ($2.44 per unit on an annualized basis), an increase of approximately 7.0 percent over the $0.57 declared in January 2011.

In January 2011, we completed an underwritten public offering of senior notes generating net proceeds of approximately $1.28 billion.  During 2011, we utilized proceeds from this debt issuance, cash from operations and our commercial paper program to meet our short-term liquidity needs and to fund our capital projects.  Our ability to continue to access capital markets for debt and equity financing under reasonable terms depends on our financial condition, credit ratings and market conditions.  We expect to fund our future capital expenditures with short- and long-term debt, the issuance of equity and operating cash flows.

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

Our primary business strategy is to increase distributable cash flow 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; 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;
·  
Consistent growth and sustainable earnings - we continue to increase NGL volumes gathered and fractionated in our Natural Gas Liquids segment and natural gas volumes processed in our Natural Gas Gathering and Processing segment, which generate earnings from predominately fee-based and POP contracts, as producers continue to develop NGL-rich resource plays that we serve in the Mid-Continent and Rocky Mountain areas.  We are investing approximately $2.7 billion to $3.3 billion in new capital projects to meet the needs of oil and natural gas producers in the Bakken Shale, the Cana-Woodford Shale and Granite Wash areas, and for additional NGL infrastructure in the Mid-Continent and Gulf Coast areas that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand, which, when completed, are anticipated to provide additional earnings and cash flows;
·  
Execute strategic acquisitions that provide long-term value - we remain a disciplined buyer of assets and continue to evaluate assets that come to market. We did not consummate any acquisitions in 2011;
·  
Manage our balance sheet and maintain strong credit ratings - our balance sheet remains strong, ending 2011 with a capital structure of 53-percent debt and 47-percent equity.  We will seek to maintain our investment-grade credit ratings; and
·  
Attract, develop and retain employees to support strategy execution - we continue to execute on our recruiting strategy that targets colleges, universities and vocational-technical schools in our operating areas.  We also continue to focus on employee development efforts with our current employees.

NARRATIVE DESCRIPTION OF BUSINESS

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

Natural Gas Gathering and Processing

Overview - Our Natural Gas Gathering and Processing segment’s operations provide nondiscretionary services to producers that include gathering and processing of natural gas produced from crude oil and natural gas wells.  We gather and process natural gas in the Mid-Continent region, which includes the NGL-rich Cana-Woodford Shale and Granite Wash formations, the Mississippian Lime formation of Oklahoma and Kansas, and the Hugoton and Central Kansas Uplift Basins of Kansas.  We also gather and/or process natural gas in two producing basins in the Rocky Mountain region:  the Williston Basin, which spans portions of Montana and North Dakota and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations; and the Powder River Basin of Wyoming.  The natural gas we gather in the Powder River Basin of Wyoming is coal-bed methane, or dry, natural gas that does not require processing or NGL extraction in order to be marketable; dry, natural gas is gathered, compressed and delivered into a downstream pipeline or marketed for a fee.

In the Mid-Continent region and the Williston Basin, unprocessed natural gas is compressed and transported through pipelines to processing facilities where volumes are aggregated, treated and processed to remove water vapor, solids and other contaminants, and to extract NGLs in order to provide marketable natural gas, commonly referred to as residue gas.   The residue gas, which consists primarily of methane, is compressed and delivered to natural gas pipelines for transportation to end users.  When the NGLs are separated from the unprocessed natural gas at the processing plants, the NGLs are in the form of a mixed, unfractionated NGL stream.  Our natural gas and NGLs are sold to affiliates and a diverse customer base.

Our natural gas processing operations primarily utilize field gas processing plants to extract NGLs and remove water vapor and other contaminants from the unprocessed natural gas stream.  Field gas processing plants process natural gas gathered from multiple producing wells.
We generally gather and process natural gas under the following types of contracts.
·  
POP - Under a POP contract, we retain a percentage of the NGLs and/or a percentage of the residue gas as payment for gathering, treating, compressing and processing the producer’s natural gas.  The producer may take its share of the NGLs and residue gas in-kind or receive its share of proceeds from our sale of the commodities.   POP contracts expose us to both natural gas and NGL commodity price risks but economically align us with the producer because we both benefit from higher commodity prices, reduced costs and improved efficiencies.  This type of contract represented approximately 37 percent and 35 percent of contracted volumes for 2011 and 2010, respectively.  There are a variety of factors that directly affect our POP margins, including:
-  
the percentages of products retained by us that represent NGL, condensate and residue gas sales volumes that we receive as payment for the services we provide;
-  
transportation and fractionation costs incurred on the NGLs we retain; and
-  
the natural gas, crude oil and NGL prices received for our retained products.
·  
Fee - Under a fee-based contract, we are paid a fee for the services provided that is based on Btus gathered, treated, compressed and/or processed.  The wellhead volume and fees received for the services provided are the main components of our margin for this type of contract.  The producer typically takes its NGLs and residue gas in-kind.  Our POP and keep-whole contracts also typically include fee provisions, which are a portion of the fees reported in this category.  Our fee-based contracts and contract provisions primarily expose us to volumetric risk with minimal commodity price risk and represented approximately 60 percent and 61 percent of contracted volumes for 2011 and 2010, respectively.
·  
Keep-Whole - Under a keep-whole contract, we extract NGLs from the unprocessed natural gas and return to the producer volumes of residue gas containing the same amount of Btus as the unprocessed natural gas that was delivered to us.  We retain the NGLs as our fee for processing.  Accordingly, we must purchase and return to the producer sufficient volumes of residue gas to replace the Btus that were removed as NGLs through the gathering and processing operation, commonly referred to as “shrink.”  This type of contract represented approximately 3 percent and 4 percent of contracted volumes for 2011 and 2010, respectively, with approximately 75 percent and 85 percent, respectively, of that volume under contracts that effectively convert into fee contracts when the gross processing spread is negative.

Our revenues from this segment are derived primarily from POP and fee contracts.  We expect that our capital projects will provide additional revenues from POP and fee contracts when completed.  We use derivative instruments to mitigate our sensitivity to fluctuations in the natural gas, crude oil and NGL prices received for our share of volumes.

Unconsolidated Affiliates - Our Natural Gas Gathering and Processing segment includes the following unconsolidated affiliates:
·  
49-percent ownership interest in Bighorn Gas Gathering, which operates a major coal-bed methane gas gathering system serving a broad production area in northeast Wyoming;
·  
37-percent ownership interest in Fort Union Gas Gathering, which gathers coal-bed methane gas produced in the Powder River Basin and delivers natural gas into the interstate pipeline grid;
·  
35-percent ownership interest in Lost Creek Gathering Company, L.L.C., which gathers natural gas produced from conventional wells in the Wind River Basin of central Wyoming and delivers natural gas into the interstate pipeline grid; and
·  
10-percent ownership interest in Venice Energy Services Co., L.L.C., a natural gas processing complex near Venice, Louisiana.

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

Market Conditions and Seasonality - Supply - Natural gas supply is affected by rig availability, operating capability and producer drilling activity, which is sensitive to commodity prices, exploration success, access to capital and regulatory control.  Higher crude oil prices and advances in horizontal drilling and completion technology are having a positive impact on drilling activity in the shale areas and other resource plays, providing an offset to the less favorable supply projections in some of the conventional resource areas.

In the Rocky Mountain region, Williston Basin volumes continue to grow as drilling activity increases, driven primarily by producer development of Bakken Shale crude oil wells, which also produce associated natural gas containing significant amounts of NGLs.  However, we have seen declines in natural gas volumes gathered in the Powder River Basin, which is dry gas.
 
In the Mid-Continent region, we have a significant amount of natural gas gathering and processing assets in western Oklahoma and southwest Kansas.  We expect increased drilling activity in the Cana-Woodford Shale and Granite Wash areas
of western Oklahoma and the Mississippian Lime formation of Oklahoma and Kansas to more than offset the volumetric declines in most conventional wells that supply our natural gas gathering and processing facilities.

Demand - Demand for natural gas gathering and processing services is typically aligned with the production of natural gas from natural gas plays or the associated natural gas from wells drilled in crude oil plays.  Gathering and processing are nondiscretionary services that producers require to market their natural gas and natural gas liquid production.  As producers continue to develop shale and other resource plays, we expect demand for our gathering and processing services to increase.  Our natural gas processing plant operations can be adjusted to respond to market conditions, such as demand for ethane.  By changing operating parameters at certain plants, we can reduce, to some extent, the amount of ethane and propane recovered if prices or processing margins are unfavorable.

Commodity Prices - Crude oil, natural gas and NGL prices are volatile due to changes in market conditions such as the amount of available supply, storage injection and withdrawal rates, available storage capacity and demand for our products by the petrochemical industry and other consumers.  We are exposed to commodity price risk and the cost of natural gas transportation at various market locations as a result of receiving commodities through our POP contracts in exchange for our services.

Seasonality - Certain of this segment’s products are subject to weather-related seasonal demand.  Cold temperatures typically increase demand for natural gas and propane, which are used to heat homes and businesses.  Warm temperatures typically drive demand for natural gas used for gas-fired electric generation needed to meet the electricity-generation demand required to cool residential and commercial properties.  Demand for iso-butane and natural gasoline, which are primarily used by the refining industry as blending stocks for motor fuel, may also be subject to some variability as automotive travel increases and as seasonal gasoline formulation standards are implemented.  During periods of peak demand for a certain commodity, prices for that product typically increase, which may influence processing decisions.

Competition - The natural gas gathering and processing business remains relatively fragmented despite significant consolidation in the industry.  We compete for natural gas supplies with major integrated oil companies, independent exploration and production companies that have gathering and processing assets, pipeline companies and their affiliated marketing companies, national and local natural gas gatherers and processors, and marketers in the Mid-Continent and Rocky Mountain regions.  The factors that typically affect our ability to compete for natural gas supplies are:
·  
fees charged under our gathering and processing contracts;
·  
pressures maintained on our gathering systems;
·  
location of our gathering systems relative to those of our competitors;
·  
location of our gathering systems relative to drilling activity;
·  
efficiency and reliability of our operations; and
·  
delivery capabilities that exist in each system and plant location.

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 plays.  We are responding to these industry conditions by making capital investments to construct and expand our assets, improve natural gas processing efficiency and reduce operating costs, evaluating consolidation opportunities to maximize earnings, and renegotiating low-margin contracts.  The principal goal of the contract renegotiation effort is to improve margins and reduce risk.

Government Regulation - The FERC has traditionally maintained that a natural gas processing plant is not a facility for the transportation or sale for resale 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.  However, we are subject to FERC regulations that require us to publicly post certain natural gas flow information on our websites.  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 various 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.

See further discussion in the “Environmental and Safety Matters” section.
Natural Gas Pipelines

Overview - Our Natural Gas Pipelines segment owns and operates regulated natural gas transmission pipelines, natural gas storage facilities and natural gas gathering systems for nonprocessed gas.  We also provide interstate natural gas transportation and storage service in accordance with Section 311(a) of the Natural Gas Policy Act.

Our FERC-regulated interstate natural gas pipeline assets transport natural gas through pipelines 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 bi-directional system that interconnects with Tennessee Gas Transmission Company’s pipeline near Portland, Tennessee, and with several interstate pipelines at the Chicago hub near Joliet, Illinois;
·  
Viking Gas Transmission, which transports natural gas from an interconnection with TransCanada’s pipeline near Emerson, Manitoba, to serve local natural gas distribution companies in Minnesota, North Dakota and Wisconsin, and terminates at a connection with ANR Pipeline Company near Marshfield, Wisconsin;
·  
Guardian Pipeline, which interconnects with several pipelines at the Chicago hub near Joliet, Illinois, and with local natural gas distribution companies in Wisconsin; and
·  
OkTex Pipeline, which has interconnects in Oklahoma, Texas and New Mexico.

Our intrastate natural gas pipeline assets in Oklahoma have access to the major natural gas producing areas, including the Cana-Woodford Shale, Granite Wash and Mississippian Lime, and transport natural gas throughout the state.  We also have access to the major natural gas producing area in south central Kansas.  In Texas, our intrastate natural gas pipelines are connected to the major natural gas producing areas in the Texas Panhandle, including the Granite Wash, and the Permian Basin, and transport natural gas throughout the western portion of the state, including the Waha Hub where other pipelines may be accessed for transportation to western markets, the Houston Ship Channel market to the east and the Mid-Continent market to the north.

We own underground natural gas storage facilities in Oklahoma, Kansas and Texas, which are connected to our intrastate natural gas pipeline assets.

Our Natural Gas Pipelines segment’s revenues are derived typically from fee-based services provided to our customers.  Our revenues are generated from the following types of fee-based contracts:
·  
Firm Service - Customers can reserve a fixed quantity of pipeline or storage capacity for the term of their contract.  Under this type contract, the customer pays a fixed fee for a specified quantity regardless of their actual usage.  The customer then typically pays incremental fees, known as commodity charges, that are based upon the actual volume of natural gas they transport or store, and/or we may retain a specified volume of natural gas in-kind for fuel.  Under the firm-service contract, the customer is generally guaranteed access to the capacity they reserve.
·  
Interruptible Service - Customers with interruptible service transportation and storage agreements may utilize available capacity after firm-service requests are satisfied or on an as-available basis.  Interruptible service customers are typically assessed fees, such as a commodity charge, based on their actual usage, and/or we may retain a specified volume of natural gas in-kind for fuel.  Under the interruptible service contract, the customer is not guaranteed use of our pipelines and storage facilities unless excess capacity is available.

Unconsolidated Affiliates - Our Natural Gas Pipelines segment includes our 50-percent interest in Northern Border Pipeline, an interstate, FERC-regulated pipeline that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana, to a terminus near North Hayden, Indiana.

See Note K 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 shale gas 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.  As new supply is developed, our customers may require incremental services to transport their production to market. Our intrastate pipelines and storage assets depend on the pace of natural gas drilling activity by producers and the decline rate of existing production in the major natural gas production areas in the Mid-Continent region, which includes the Cana-Woodford Shale, Granite Wash and Mississippian Lime formations, Hugoton Basin and Central Kansas Uplift Basin.  The supply of natural gas for Viking Gas Transmission and Northern Border Pipeline originates in Canada.  Significant factors that can impact the supply of Canadian natural gas transported by our pipelines are the Canadian natural gas available for export, Canadian storage capacity and demand for Canadian natural gas in Canada and United States consumer markets.  Guardian Pipeline and Midwestern Gas Transmission access supply from the major producing regions of the Mid-Continent, Rocky Mountains, Canada and Gulf Coast.
Demand - Demand for natural gas pipeline transportation service and natural gas storage is related directly to demand for natural gas in the markets that the natural gas pipelines and storage facilities serve, and is affected by weather, the economy and natural gas and NGL price volatility.  Our pipelines primarily serve end-users, such as natural gas distribution companies and electric-generation companies, that require natural gas to operate their business and generally are not impacted by price location differentials.  However, narrower location differentials may impact demand for our services from natural gas marketers as discussed below under “Commodity Prices.”  Demand for our services can also be impacted as coal-fired electric generators consider natural gas as an alternative fuel.  Recent EPA regulations on emissions from coal-fired electric-generation plants-including the Cross-State Air Pollution Rule, Maximum Achievable Control Technology Standards, and the Mercury and Air Toxics Standards–may increase the demand for natural gas as well as related transportation and storage services.   The effect of weather on our natural gas pipelines operations is discussed below under “Seasonality.”  The strength of the economy directly impacts manufacturing and industrial companies that consume natural gas.  Commodity price volatility can influence producers’ decisions related to the production of natural gas, the level of NGLs processed from natural gas, and natural gas storage injection and withdrawal activity.

Commodity Prices - The increase in natural gas supply from shale gas development has caused natural gas prices to decline and natural gas location and seasonal price differentials to narrow across most of the regions where we operate.  We are exposed to market risk when existing contracts expire and are subject to renegotiation with customers that have competitive alternatives and analyze the market price differential between receipt and delivery points along the pipeline, also known as location differential, to determine their expected gross margin.  The anticipated margin and its variability are important determinants of the transportation rate customers are willing to pay.  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.  Our fuel costs and the value of the retained fuel in-kind are also impacted by changes in the price of natural gas.

Seasonality - Demand for natural gas is seasonal.  Weather conditions throughout North America can significantly impact regional natural gas supply and demand.  High temperatures can increase demand for gas-fired electric generation needed to meet the electricity demand required to cool residential and commercial properties.  Cold temperatures can lead to greater demand for our transportation services due to increased demand for natural gas to heat residential and commercial properties.  Low precipitation levels can 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 demand charges, is not significantly impacted by seasonal throughput variations.  However, when transportation agreements expire, seasonal demand can impact 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 power-generation users.  The majority of our storage capacity is contracted under firm-service agreements.  A small portion of our storage capacity is retained for operational purposes.

Competition - Our natural gas pipelines and storage facilities compete directly with other intrastate and interstate pipeline companies and other storage facilities in providing natural gas transportation and storage services.  Our natural gas assets primarily serve local distribution companies, large industrial companies, municipalities, irrigation customers, power-generation facilities and marketing companies.  Competition among pipelines and natural gas storage facilities is based primarily on fees for services, quality of services provided, current and forward natural gas prices, and proximity to natural gas supply areas and markets.  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.  We believe that we compete effectively with our pipelines and storage assets due to their strategic locations connecting supply areas to market centers and other pipelines.

Government Regulation - 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 segment, 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.

Likewise, 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 gathering and storage are not subject to rate regulation.

See further discussion in the “Environmental and Safety Matters” section.
Natural Gas Liquids

Overview - Our natural gas liquids assets provide nondiscretionary services to producers that consist of facilities that gather, fractionate and treat NGLs and store NGL products primarily in Oklahoma, Kansas and Texas.  We own or have an ownership interest in FERC-regulated natural gas liquids gathering and distribution pipelines in Oklahoma, Kansas, Texas, 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 NGLs from unprocessed natural gas, are connected to our gathering systems.  We own and operate truck and rail-loading and unloading facilities that interconnect with our fractionation and pipeline assets.  Through recent expansions to our rail facilities in Kansas, we have begun receiving raw NGLs transported by rail from the Williston Basin to our Kansas fractionation facilities in 2012.  We will continue to receive these Williston Basin NGLs through our rail-loading facilities until construction is completed on our Bakken Pipeline, which is expected to be in service in the first half of 2013.

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 the 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 and propane distributors.  We also purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing segment.

Revenues for our Natural Gas Liquids segment are derived primarily from fee-based services provided to our customers and physical optimization of our assets.  Our fee-based services have increased primarily due to our previously completed capital projects, including Overland Pass Pipeline and its associated lateral pipelines, expansion of our fractionation capacity and Arbuckle Pipeline.  Our sources of revenue are categorized as exchange services, optimization and marketing, pipeline transportation, isomerization and storage, which are defined as follows:
·  
Our exchange services business primarily collects fees to gather, fractionate and treat unfractionated NGLs, thereby converting them into marketable NGL products that are stored and shipped to a market center or customer-designated location.
·  
Our optimization and marketing business utilizes our assets, contract portfolio and market knowledge to capture location and seasonal price differentials.  We transport NGL products between the Mid-Continent and Gulf Coast in order to capture the location price differentials between the two market centers.  Our natural gas liquids storage facilities are also utilized to capture seasonal price variances.
·  
Our pipeline transportation business transports raw NGLs, finished NGL products and refined petroleum products primarily under our FERC-regulated tariffs.  Tariffs specify the rates we charge our customers and the general terms and conditions for NGL transportation service on our pipelines.
·  
Our isomerization business captures the price differential when normal butane is converted into the more valuable iso-butane at our isomerization unit in Conway, Kansas.  Iso-butane is used in the refining industry to increase the octane of motor gasoline.
·  
Our storage business collects fees to store NGLs at our Mid-Continent and Gulf Coast facilities.

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, which operates a terminal and pipeline system that transports refined petroleum products in Kansas, Nebraska and Iowa.

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

Market Conditions and Seasonality - Supply - Supply for our Natural Gas Liquids segment depends on the pace of crude oil and natural gas drilling activity by producers, the decline rate of existing production and the NGL content of the natural gas that is produced and processed.  We are seeing rapid NGL supply growth within our footprint as producers continue to aggressively drill in a number of NGL-rich resource plays in the Mid-Continent and Rockies.  We expect the overall supply of NGLs to continue to increase as well as demand for our fee-based services as a result of the development of these resource plays.  Many new natural gas processing plants are being constructed in Oklahoma and the Texas Panhandle to process NGL-rich natural gas being produced in the Cana-Woodford Shale, the Granite Wash, the Woodford Shale and the emerging
Mississippian Lime formations. The unfractionated NGLs that we transport are primarily gathered from natural gas processing plants in Oklahoma, Kansas, Texas and the Rocky Mountain region.  Our fractionation operations receive NGLs from a variety of processors and pipelines, including affiliates, located in these regions.

Our Natural Gas Liquids segment is also affected by operational or market-driven changes that impact the output of natural gas processing plants to which we are connected.  The differential between the composite price of NGL products and the price of natural gas, particularly the differential between the price of ethane and the price of natural gas, may influence processing plant NGL output.  During 2011, ethane prices remained significantly above natural gas prices on a relative Btu basis, which resulted in an economic incentive for ethane recovery from natural gas processing plants that deliver NGLs to our natural gas liquids gathering pipelines.  Natural gas and/or NGL pipeline capacity constraints may impact the output of natural gas processing plants in total or for specific NGL products in the future.  During 2011, we experienced limited reductions of supply related to changes in plant output as a result of pipeline capacity constraints.

Demand - Demand for NGLs and the ability of natural gas processors to successfully and economically sustain their operations impacts 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, which are 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 fiber.  During 2011, several petrochemical companies announced 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 as a petrochemical feedstock in the United States.  These projects are expected to significantly increase ethane demand over the next five years.  In addition, international demand for propane is expected to impact the NGL market in the future.  We expect this increase in demand for NGLs to add incremental fee-based earnings to our exchange services business.

Commodity Prices - In recent years, crude oil, natural gas and NGL prices have been volatile due to market conditions.  The increase in crude oil prices and the abundance of NGLs produced from the development of shale and other resource plays has made NGL feedstocks to the petrochemical industry more competitive.  We are exposed to market risk associated with adverse 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 impact our NGL purchases, sales, distribution, exchange and storage revenue.  When natural gas prices are higher relative to NGL prices, NGL production may decline, which could negatively impact our exchange services and transportation revenues.  When the location differential between the Mid-Continent and Gulf Coast market centers is narrow, optimization opportunities and NGL shipments may decline, resulting in a decline in earnings from our NGL optimization and marketing businesses.  During the second half of 2011, due to strong Mid-Continent supply growth, robust Gulf Coast demand and limited pipeline capacity, NGL prices in the Mid-Continent Market Center at Conway, Kansas, were significantly lower relative to prices in the Gulf Coast market center at Mont Belvieu, Texas.  NGL storage revenue may be impacted by price volatility and forward pricing of NGL physical contracts versus the price of NGLs on the spot market.

Seasonality - Our NGL fractionation and pipeline operations typically experience minimal seasonal variation.  Some NGL products stored and distributed 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 grain 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 are in place.

Competition - Our natural gas liquids business competes with other fractionators, intrastate and interstate pipeline companies, storage providers and gatherers for NGL supplies in the Rocky Mountain, Mid-Continent and Gulf Coast regions.  The factors that typically affect our ability to compete for NGL supplies 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;
·  
pressures maintained on our gathering systems;
·  
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; and
·  
delivery capabilities that exist in each system, plant, fractionator and storage location.
We are responding 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 have also recently announced plans for new pipeline and fractionation projects to address the growing NGL supply and petrochemical demand.  When completed, our growth projects and those of our competitors will impact NGL prices and narrow location differentials between the Mid-Continent and Gulf Coast market centers.  We believe our fractionation, pipelines and storage assets are located strategically, connecting diverse supply areas to market centers.

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 Kansas and Texas, our intrastate natural gas liquids pipelines that provide common carrier service are subject to the jurisdiction of the KCC and RRC, respectively, which have oversight regarding services provided.

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

SEGMENT FINANCIAL INFORMATION

Operating Income, Customers and Total Assets - See Note N 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.

FINANCIAL MARKETS LEGISLATION

The Dodd-Frank Act represents a far-reaching overhaul of the framework for regulation of United States financial markets.  Various regulatory agencies, including the SEC and the CFTC, have proposed regulations for implementation of many of the provisions of the Dodd-Frank Act.  Although the CFTC has issued final regulations for certain provisions of the Dodd-Frank Act, many remain outstanding.  In November 2011, the CFTC published final rules on speculative position limits, which we do not expect to impact directly our current risk-management practices.  In December 2011, the CTFC issued an order that further defers the effective date of the provisions of the Dodd-Frank Act that require a rulemaking, such as definitions of certain terms, until the earlier of the effective date of the final rule defining the reference terms or July 16, 2012.  Until the remaining final regulations are established, we are unable to ascertain how we may be affected by them.  Based on our assessment of the regulations issued to date and those proposed, we expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation.  We also may incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations; however, we do not believe the costs will be material.  These requirements could affect adversely market liquidity and pricing of derivative contracts making it more difficult to execute our risk-management strategies in the future.  Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.
  
ENVIRONMENTAL AND SAFETY MATTERS

Pipeline Safety - We are subject to Pipeline and Hazardous Materials Safety Administration regulations, including 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 new law increased the 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:
·  
an evaluation of whether hazardous liquid and natural gas pipeline integrity-management requirements should be expanded beyond current high-consequence areas;
·  
a review of all natural gas and hazardous liquid 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 pipelines previously untested in high-consequence areas operating above 30 percent yield strength.

The potential capital and operating expenditures related to this legislation, the associated regulations or other new pipeline safety regulations are unknown.
Air and Water Emissions - The Clean Air Act, the Clean Water Act and analogous state laws 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 greenhouse gas emissions are under way.  We are monitoring federal and state legislation to assess the potential impact on our operations.  The EPA’s Mandatory Greenhouse Gas Reporting Rule released in September 2009 requires greenhouse gas emissions reporting for affected facilities on an annual basis and requires us to track the emission equivalents for all NGLs delivered to our customers.  Our 2010 total reported emissions was less than 53.2 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, and carbon dioxide equivalents from NGL products delivered to customers, as if all such fuel and NGL products were combusted and carbon dioxide injected directly into disposal wells.  The next required reporting period for 2011 greenhouse gas emissions will be due March 31, 2012.  Also, the EPA released a subpart to the Mandatory Greenhouse Gas Reporting Rule that will require the reporting of vented and fugitive emissions of methane from our facilities.  The new requirements began in January 2011, with the first reporting of fugitive emissions due September 30, 2012.  We do not expect the cost to gather this emission data 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 greenhouse gas emissions, including carbon dioxide and methane.  At this time, no rule or legislation has been enacted that assesses any costs, fees or expenses on any of these emissions.

In May 2010, the EPA finalized the “Tailoring Rule” that will regulate greenhouse gas emissions at new or modified facilities that meet certain criteria.  Affected facilities will be required to review best available control technology, conduct air-quality analysis, impact analysis and public reviews with respect to such emissions.  Since January 2011, the rule has been in the process of being phased in, and at current emission threshold levels, we believe it will have a minimal impact on our existing facilities.  The EPA has stated it will consider lowering the threshold levels over the next five years, which could increase the impact on our existing facilities; however, potential costs, fees or expenses associated with the potential adjustments are unknown.

In addition, the EPA issued a rule on air-quality standards, “National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP, with a compliance date in 2013.  The rule will require capital expenditures over the next two years for the purchase and installation of new emissions-control equipment.  We do not expect these expenditures to have a material impact on our results of operations, financial position or cash flows.

On July 28, 2011, the EPA issued a proposed rule package that would change the air emission New Source Performance Standards and Maximum Achievable Control Technology requirements applicable to natural gas production, processing, transmission and underground storage.  The proposed rules would impact emission limits for specific equipment through the use of controls; however, potential costs associated with the proposed rules currently are unknown.

Superfund - The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or Superfund, imposes liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a hazardous substance into the environment.  These persons include the owner or operator of a facility where the release occurred and 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.  In 2011, we received notice from the EPA of potential liability at the U.S. Oil Recovery Superfund Site location in Harris County, Texas.  We are named a potentially responsible party as a result of waste disposal at the now-abandoned site.  We do not expect our current responsibilities under CERCLA, for this facility or any other, to have a material impact on our results of operations, financial position or cash flows.

Chemical Site Security - The United States Department of Homeland Security (Homeland Security) released an interim rule in April 2007 that requires companies to provide reports on sites where certain chemicals, including many hydrocarbon products, are stored.  We completed the Homeland Security assessments, 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 - Homeland Security’s Transportation Security Administration and the United States Department of Transportation 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 taking steps to minimize the impact of our operations on the environment.  These strategies include:  (i) developing and maintaining an accurate greenhouse gas 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 (iv) following developing technologies to capture carbon dioxide to keep it from reaching the atmosphere.

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 methane gas during pipeline and facility maintenance and operations.  Our most recent calculation of our annual lost-and-unaccounted-for natural gas, for all of our business operations, is less than 1 percent of total throughput.

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, ONEOK Partners GP and NBP Services (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 operates Guardian Pipeline, Viking Gas Transmission and Midwestern Gas Transmission according to each pipeline’s operating agreement.  ONEOK Partners GP may purchase services from ONEOK and its affiliates pursuant to the terms of the Services Agreement.  As of January 31, 2012, we utilized some or all of the services of 4,795 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 on Form 10-Q, 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, Governance Guidelines, Partnership Agreement and the written charter of our Audit Committee are also 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 discuss key factors, our investors need to be aware that other risks may prove to be important in the future.  New risks may emerge at any time, and we cannot predict such risks or estimate the extent to which they may affect our financial performance.  Investors should carefully consider 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 Operation.

RISKS INHERENT IN OUR BUSINESS

Market volatility and capital availability could affect adversely our business.

The capital and 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 companies.  Our ability to grow could be constrained if we do not have regular access to the capital and credit markets.  Similar or more severe levels of market disruption and volatility may have an adverse affect 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 cost and increasingly restrictive covenants.
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 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 cash flow.

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 for the sale of NGL products in our natural gas liquids business.  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 NGL fractionation capacity;
·  
the level of consumer product demand;
·  
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 price of natural gas, crude oil, NGL and liquefied natural gas imports;
·  
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.  As commodity prices decline, we are paid less for our commodities, thereby reducing our cash flow.  In addition, production could also decline.

We may not be able to generate sufficient cash from operations to allow us to pay quarterly distributions at current 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.  Our ability to pay quarterly distributions depends primarily on cash flow, including cash flow from financial reserves and working capital borrowings, and not solely on profitability, which is affected by noncash items.  As a result, we may pay cash distributions during periods when we record net losses and may be unable to pay cash distributions during periods when we record net income.

We do not hedge fully against commodity price changes.  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 arising from adverse changes in commodity prices.  Our primary commodity price exposures arise from:
·  
the value of the NGLs and natural gas we receive in exchange for the natural gas gathering and processing services we provide;
·  
the differentials between NGL and natural gas prices associated with our keep-whole contracts;
·  
the differential between the individual NGL products with respect to our NGL transportation, fractionation and exchange agreements;
·  
the locational differentials in the price of natural gas and NGLs with respect to our natural gas and NGL transportation businesses;
·  
the seasonal differentials in natural gas and NGL prices 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 fluctuations in natural gas, NGL and crude oil prices, we use physical forward transactions and commodity derivative instruments such as futures contracts, swaps 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 to hedge market risk may result in reduced income.

We utilize financial instruments 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.

Increases 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 increases in interest rates above current levels.  

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 ONEOK Partners GP senior management and the Audit Committee of ONEOK Partners GP Board of Directors to assist us in managing risks.  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 affect on our earnings, financial position or cash flows.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010, the Dodd-Frank Act was enacted, which provides for new statutory and regulatory requirements for certain swap transactions.  Certain financial transactions will be required to be cleared on exchanges, and cash collateral will be required for these transactions.  However, the Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users and includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and to the parties to those transactions.  Additionally, the Dodd-Frank Act calls for various regulatory agencies, including the SEC and the CFTC, to establish regulations for implementation of many of the provisions of the act.  It also requires the CFTC to establish new position trading limits.

We expect to be able to continue to participate in financial markets for hedging certain risks inherent in our business, including commodity and interest-rate risks; however, the costs of doing so may increase as a result of the new legislation.  We may also incur additional costs associated with our compliance with the new regulations and anticipated additional record keeping, reporting and disclosure obligations.  These requirements could affect adversely market liquidity and pricing of derivative contracts making it more difficult to execute our risk-management strategies in the future.  Also, the anticipated increased costs of compliance by dealers and counterparties likely will be passed on to customers, which could decrease the benefits of hedging to us and could reduce our profitability and liquidity.
Our inability to develop and execute growth projects and acquire new assets 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.  Accordingly, 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 risks and supply risks should adequate natural gas or NGL supplies be unavailable upon completion of the facilities.

One of the ways we intend to grow our business 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 require significant capital expenditures, which may exceed our estimates, and involves numerous regulatory, environmental, political, legal and weather-related uncertainties.  Construction projects in our industry may increase demand for labor, materials and rights of way, which may, in turn, impact our costs and schedule.  If we undertake these projects, we may not be able to complete them on schedule or at the budgeted cost.  Additionally, 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 supplies committed to these facilities prior to their construction.  Additionally, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize.  We may also 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.  As a result, new facilities may not be able to attract enough natural gas or NGLs to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition.

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 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 materially adversely affect 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 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 aimed at our facilities could adversely affect our business.

Since the September 11, 2001, terrorist attacks, 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-integrity programs and repairs may impose significant costs and liabilities.

Pursuant to a United States Department of Transportation rule, pipeline operators are required to develop integrity-management programs for intrastate and interstate natural gas and natural gas liquids pipelines that could affect high-consequence areas in the event of a release of product.  As defined by applicable regulations, high-consequence areas include areas near the route of a pipeline with high population densities, facilities occupied by persons of limited mobility or outdoor or indoor areas where at least twenty people periodically gather.  The rule requires operators to identify pipeline segments that could impact a high-consequence area; improve data collection, integration and characterization of threats applicable to each segment and implement preventive and mitigating actions; perform ongoing assessments of pipeline integrity; and repair and remediate the pipeline as necessary.  These testing programs could cause us to incur significant capital and operating expenditures to make repairs or remediate, as well as initiate preventive or mitigating actions that are determined to be necessary.

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:
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the Clean Air Act and analogous state laws that impose obligations related to air emissions;
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the Clean Water Act and analogous state laws that regulate discharge of wastewater from our facilities to state and federal waters;
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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;
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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; and
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the EPA has issued a rule on air-quality standards, known as RICE NESHAP, with a compliance date in 2013.

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, 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 “Environmental and Safety Matters” and in Note M 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 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 greenhouse gas emissions.

Greenhouse gas 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 greenhouse gases, 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 greenhouse gases.

We believe it is likely that future governmental legislation and/or regulation may require us either to limit greenhouse gas 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 greenhouse gases 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 greenhouse gas 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 greenhouse gas 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 greenhouse gas 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 greenhouse gas 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 may not be able to pass on the higher costs to our customers or recover all costs related to complying with greenhouse gas emission regulatory requirements, which could have a material adverse effect on our results of operations, cash flows or financial condition.

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

There is a growing belief that emissions of greenhouse gases 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 revenues.  Severe weather impacts our operating territories primarily through hurricanes, thunderstorms, tornadoes 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 greenhouse gases as a financial risk, this could negatively affect 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 greenhouse gas emitters, based on links drawn between greenhouse gas emissions and climate change.

Continued development of new supply sources could impact demand.

The discovery of nontraditional 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, New York, 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 nontraditional natural gas production areas may compete with and displace volumes from the Mid-Continent, Rocky Mountains and Canadian supply sources in certain of our markets.  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 oil and natural gas wells, which could adversely impact our revenues by decreasing the volumes of unprocessed natural gas transported on our or our joint ventures’ natural gas pipelines.

The natural gas industry is increasingly relying on natural gas supplies from unconventional sources, such as shale, tight sands and coal-bed methane gas.  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, 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 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 gathered, treated, processed and transported on our or our joint ventures’ natural gas pipelines, several of which gather unprocessed natural gas from areas in which 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 supplies 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 the level of drilling and production in the Mid-Continent, Rocky Mountain, Texas and Gulf Coast regions declines substantially near our assets, our volumes and revenues could decline.

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, Texas and Gulf Coast regions.  Drilling and production are impacted by factors beyond our control, including:
·  
demand and prices for natural gas, NGLs and crude oil;
·  
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 pipelines from the producing areas and our facilities.

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 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 results of operations and cash flows available for distributions.

Mergers among 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 of a similar magnitude, 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 $1.0 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 and results of operations.

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.

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 may also 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.

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 ratemaking 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.

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.

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 meters that we use throughout our natural gas 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 effect our earnings and cash flows.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.

Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions.  If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected.  Our financial results could also be adversely affected 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 sectors, and this may subject our business to increased risks.  Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse effect on our businesses.  In addition, cyber attacks on our customer and employee data may result in a financial loss and may negatively impact our reputation.  Third-party systems on which we rely could also suffer operational system failure.  Any of these occurrences could disrupt one or more of our businesses, result in potential liability or reputational damage or otherwise have an adverse affect on our financial results.

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 which 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.

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 deterioration of their financial condition as a result of changing market conditions 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 as we deem appropriate.  If we fail to assess adequately the creditworthiness of existing or future customers or counterparties, unanticipated deterioration in their creditworthiness and any resulting nonpayment and/or nonperformance could adversely impact our results of operations.  In addition, if any of our customers or counterparties file for bankruptcy protection, this could have a material negative impact on our results of operations.
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.  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.

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

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, 11,800,000 common units and the entire 2-percent general partner interest in us, which together constituted a 42.8-percent ownership interest in us as of December 31, 2011.  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 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, ONEOK Partners GP and NBP Services 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, ONEOK Partners GP and NBP Services 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, ONEOK Partners GP and NBP Services 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, ONEOK Partners GP and NBP Services 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 or not to consent to any merger or consolidation of us;
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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;
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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;
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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
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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.

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 February 2010 public offering of common units, ONEOK and its subsidiaries own a 42.8-percent aggregate equity interest in us.  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.  Seven of the 11 members of the Board of Directors of our general partner are either members of ONEOK’s Board of Directors or executive management of ONEOK.  Four independent members and one management member of the Board of Directors of our general partner are also 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 Committee.  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:
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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;
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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;
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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;
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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;
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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;
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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
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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.
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” (Stable) and Prime-2, respectively, by Moody’s and “BBB” (Stable) and A2, 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 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, 2011, we had total indebtedness of approximately $3.9 billion.  Our indebtedness could have significant consequences.  For example, it could:
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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;
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impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general business purposes;
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diminish our ability to withstand a downturn in our business or the economy;
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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;
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limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
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place us at a competitive disadvantage compared to 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.
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, or 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 legal 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 to 1.

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.

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:
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our unitholders’ proportionate ownership interest in us will decrease;
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the distributions to our general partner related to its incentive distribution rights may increase and the distribution paid on each unit may decrease;
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the relative voting strength of each previously outstanding unit may be diminished; and
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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.

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.  Unitholders may also have liability to repay distributions.

As a limited partner in a limited partnership organized under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if they participate in the “control” of our business.  Our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are made expressly without recourse to our general partner.  In addition, the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.  The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been established clearly in some of the states in which we do business.

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 recent 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:
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the Intermediate Partnership incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or the Intermediate Partnership contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or
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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:
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was insolvent or rendered insolvent by reason of the issuance of the guarantee;
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was engaged or about to engage in a business or transaction for which its remaining assets constituted unreasonably small capital; or
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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:
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the sum of its debts, including contingent liabilities, were greater than the fair saleable value of all of its assets at a fair valuation;
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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
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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 Footnote K 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 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 would be effectively 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, it is possible, in certain circumstances, for a partnership such as ours to be treated as a corporation for federal income tax purposes.  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 income taxes at varying rates.  Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders.  Because a 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.

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 are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation.  For example, starting January 1, 2008, we have been required to pay Texas franchise tax each year at a maximum effective rate of 0.7 percent of our gross revenue that is apportioned to Texas in the prior year.  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 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.  Recently, members of the United States Congress considered substantive changes to the existing federal income tax laws that would have affected the tax treatment of certain publicly traded partnerships.  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 of these changes or any other proposals will be enacted ultimately.  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 adversely impact 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 impact 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 impact 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.

A unitholder’s share of our income will 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 will be treated as partners to whom we will allocate taxable income, which will be affected by noncash items and 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.
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 the 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.

We will treat each purchaser of units as having the same tax benefits without regard to the 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 purpose 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.  The use of this proration method may not be permitted under existing Treasury regulations.  If the IRS were to challenge our proration method or new Treasury regulations were issued, 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.

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, we would be treated as a new partnership and would be required to make new tax elections, and we could be subject to penalties if we are unable to determine that a technical termination occurred.

The IRS has announced recently a publicly traded partnership technical termination relief procedure, whereby if a publicly traded partnership that has technically terminated 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.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner.  Our methodology may be viewed as understating the value of our assets.  In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders.  Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets.  The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

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 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 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 10,300 miles and 5,600 miles of natural gas gathering pipelines in the Mid-Continent and Rocky Mountain regions, respectively;
·  
nine natural gas processing plants, with approximately 645 MMcf/d of processing capacity, in the Mid-Continent region, and five natural gas processing plants, with approximately 215 MMcf/d of processing capacity, in the Rocky Mountain region; and
·  
approximately 24 MBbl/d of natural gas liquids fractionation capacity at various natural gas processing plants in the Mid-Continent and Rocky Mountain regions.

Utilization - The utilization rates for our natural gas processing plants were approximately 71 percent and 69 percent for 2011 and 2010, respectively.
 
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 3.1 Bcf/d of peak transportation capacity;
·  
approximately 5,600 miles of intrastate natural gas gathering and state-regulated intrastate transmission pipelines with peak transportation capacity of approximately 3.4 Bcf/d; and
·  
approximately 51.7 Bcf of total active working natural gas storage capacity.

Our storage includes five underground natural gas storage facilities in Oklahoma, three underground natural gas storage facilities in Kansas and three underground natural gas storage facilities in Texas.  One of our natural gas storage facilities outside of Hutchinson, Kansas, has been idle since 2001.  In compliance with a KDHE order, we began injecting brine into that facility in the first quarter of 2007 in order to ensure the long-term integrity of the idled facility.  We expect to complete the injection process by the end of 2012.  Monitoring of the facility and review of the data for the geo-engineering studies are ongoing, in compliance with a KDHE order, while we evaluate the alternatives for the facility.  Following the testing of the gathered data, we expect that the facility will be returned to storage service, although most likely for a product other than natural gas.  The return to service will require KDHE approval.  It is possible, however, that testing could reveal that it is not safe to return the facility to service or that the KDHE will not grant the required permits to resume service.

Utilization - Our natural gas pipelines were approximately 83 percent and 87 percent subscribed for 2011 and 2010, respectively, and our storage facilities were fully subscribed both years.

Natural Gas Liquids

Property - Our Natural Gas Liquids segment owns the following assets:
·  
approximately 2,500 miles of natural gas liquids gathering pipelines with peak gathering capacity of approximately 629 MBbl/d;
·  
approximately 160 miles of natural gas liquids distribution pipelines with peak transportation capacity of approximately 66 MBbl/d;
·  
approximately 780 miles of FERC-regulated natural gas liquids gathering pipelines with peak capacity of approximately 213 MBbl/d;
·  
approximately 3,500 miles of FERC-regulated natural gas liquids and refined petroleum products distribution pipelines with peak capacity of 708 MBbl/d;
·  
two natural gas liquids fractionators with combined operating capacity of approximately 260 MBbl/d, which are located in Oklahoma and Kansas;
·  
a natural gas liquids fractionator with operating capacity of 150 MBbl/d located at the Bushton facility in Kansas, a portion of which prior to June 30, 2011, was leased through an affiliate;
·  
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; and
·  
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.

In addition, we lease approximately 2.5 MMBbl of combined NGL storage capacity at facilities in Kansas and Texas.

Utilization - The utilization rates for our various assets, including leased assets, for 2011 and 2010, respectively, were as follows:
·  
our non-FERC-regulated natural gas liquids pipelines were approximately 71 percent and 56 percent;
·  
our FERC-regulated natural gas liquids gathering pipelines were approximately 97 percent and 70 percent;
·  
our FERC-regulated natural gas liquids distribution pipelines were approximately 65 percent and 63 percent;
·  
our average contracted natural gas liquids storage volumes were approximately 63 percent and 64 percent of storage capacity; and
·  
our natural gas liquids fractionators were approximately 89 percent and 93 percent.

We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in service.  The utilization rates of our FERC-regulated natural gas liquids gathering pipelines reflect Overland Pass Pipeline and its related lateral pipelines until Overland Pass Pipeline Company was deconsolidated in September 2010.  Our fractionation utilization rate reflects approximate proportional capacity associated with our ownership interests.

ITEM 3.
LEGAL PROCEEDINGS

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price, et al. v. Gas Pipelines, et al.,  f/k/a Quinque Operating Company, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Boles I”).  Plaintiffs brought suit on May 28, 1999, against ONEOK and its division, Oklahoma Natural Gas, four of our subsidiaries, Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), as well as approximately 225 other defendants.  Plaintiffs sought class certification for their claims for monetary damages, alleging that the defendants had underpaid gas producers and royalty owners throughout the United States by intentionally understating both the volume and the heating content of purchased gas.  After extensive briefing and a hearing, the Court refused to certify the class sought by plaintiffs.  Plaintiffs then filed an amended petition limiting the purported class to gas producers and royalty owners in Kansas, Colorado and Wyoming and limiting the claim to undermeasurement of volumes.  On September 18, 2009, the Court denied the plaintiffs' motions for class certification, which, in effect, limits the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas.  The plaintiffs’ motion for reconsideration of the Court’s denial of class certification was denied on March 31, 2010.  This case continues but it is now limited to the individual claims of the two named plaintiffs.

Thomas F. Boles, et al. v. El Paso Corporation, et al. (f/k/a Will Price and Stixon Petroleum, et al. v. Gas Pipelines, et al.), 26th Judicial District, District Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Boles II”).  This action was filed by the plaintiffs on May 12, 2003, after the Court denied class status in Boles I. Plaintiffs are seeking monetary damages based upon a claim that 21 groups of defendants, including ONEOK and its division, Oklahoma Natural Gas, four of our subsidiaries, Mid-Continent Market Center, L.L.C., ONEOK Field Services Company, L.L.C., ONEOK WesTex Transmission, L.L.C. and ONEOK Hydrocarbon, L.P. (formerly Koch Hydrocarbon, LP, successor to Koch Hydrocarbon Company), intentionally underpaid gas producers and royalty owners by understating the heating content of purchased gas in Kansas, Colorado and Wyoming.  Boles II has been consolidated with Boles I for the determination of whether either or both cases may be certified properly as class actions.  On September 18, 2009, the Court denied the plaintiffs' motions for class certification, which, in effect, limits the named plaintiffs to pursuing individual claims against only those defendants who purchased or measured their gas.  The plaintiffs’ motion for reconsideration of the Court’s denial of class certification was denied on March 31, 2010.  This case continues but it is now limited to the individual claims of the two named plaintiffs.

ITEM 4.
MINE SAFETY DISCLOSURES

Not applicable.
PART II

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

In July 2011, a two-for-one split of our common and Class B units was completed, and our Partnership Agreement was amended to adjust the formula for distributing available cash among our general partner and limited partners to reflect the unit split.  As a result, we have adjusted all unit and per-unit amounts contained herein to be presented on a post-split basis.

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
    
Year Ended
  
   
December 31, 2011
    
December 31, 2010
  
   
High
    
Low
    
High
    
Low
  
First Quarter
   $ 41.83     $ 39.42     $ 33.34     $ 28.99  
Second Quarter
   $ 43.18     $ 40.00     $ 32.67     $ 27.98  
Third Quarter
   $ 46.62     $ 37.74     $ 37.46     $ 31.79  
Fourth Quarter
   $ 57.94     $ 45.05     $ 40.76     $ 37.25  

At February 14, 2012, there were 659 holders of record of our 130,827,354 outstanding common units.  ONEOK and its affiliates own all of the Class B units, 11,800,000 common units and the entire 2-percent general partner interest in us, which together constituted a 42.8-percent ownership interest in us.

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:
   
Years Ended December 31,
  
   
2011
    
2010
    
2009
  
First Quarter
   $ 0.570     $ 0.550     $ 0.540  
Second Quarter
   $ 0.575     $ 0.555     $ 0.540  
Third Quarter
   $ 0.585     $ 0.560     $ 0.540  
Fourth Quarter
   $ 0.595     $ 0.565     $ 0.545  

In January 2012, our general partner declared a cash distribution of $0.61 per unit ($2.44 per unit on an annualized basis) for the fourth quarter of 2011, which was paid on February 14, 2012, to unitholders of record as of January 31, 2012.

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 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 $609.4 million, $563.2 million and $500.3 million for 2011, 2010 and 2009, respectively, which included an incentive distribution to our general partner of $123.4 million, $103.5 million and $84.7 million for 2011, 2010 and 2009, 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, 2006, and ending on December 31, 2011.  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, 2006, and at the End of Every Year Through December 31, 2011,
Among ONEOK Partners, L.P., the S&P 500 Index and the Alerain MLP Index
 
 
 
Cumulative Total Return
  
 
Years Ended December 31,
  
   
2007
    
2008
    
2009
    
2010
    
2011
  
                               
ONEOK Partners, L.P.
   $ 102.65     $ 82.11     $ 122.20     $ 166.55     $ 255.03  
S&P 500 Index
   $ 105.49     $ 66.47     $ 84.06     $ 96.74     $ 98.76  
Alerian MLP Index (a)
   $ 112.68     $ 71.26     $ 125.70     $ 170.83     $ 194.62  
(a) - The Alerian MLP Index measures the composite performance of the 50 most prominent energy master limited
  
partnerships.
                                        
ITEM 6.
SELECTED FINANCIAL DATA

The following table sets forth our selected financial data for the periods indicated:
   
Years Ended December 31,
  
   
2011
    
2010
    
2009
    
2008
    
2007
  
   
(In millions of dollars, except per unit data)
  
Revenues
   $ 11,322.6     $ 8,675.9     $ 6,474.5     $ 7,720.2     $ 5,831.6  
Net income
   $ 830.9     $ 473.3     $ 434.7     $ 626.1     $ 408.2  
Net income attributable to ONEOK Partners, L.P.
   $ 830.3     $ 472.7     $ 434.4     $ 625.6     $ 407.7  
Limited partners' net income per unit
   $ 3.35     $ 1.75     $ 1.80     $ 3.01     $ 2.11  
Distributions paid per common unit (a)
   $ 2.325     $ 2.230     $ 2.165     $ 2.105     $ 1.990  
Total assets
   $ 8,946.7     $ 7,920.1     $ 7,953.3     $ 7,254.3     $ 6,112.1  
Long-term debt, including current maturities
   $ 3,876.6     $ 2,818.5     $ 3,084.0     $ 2,601.4     $ 2,617.3  
(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 our “Description of the Business” in Item 1, Business, and our audited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Annual Report.

RECENT DEVELOPMENTS

The following discussion highlights some of our planned activities, recent achievements and significant issues affecting us.  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 Operation, our Consolidated Financial Statements and Notes to Consolidated Financial Statements for additional information.

Growth Projects - Drilling rig counts are higher compared with 2010, and related development activities continue to progress in many regions of our operations.  We expect continued development of the reserves in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale, Granite Wash and Mississippian Lime areas in the Mid-Continent region.  Increasing natural gas and NGL production resulting from these activities and higher petrochemical industry demand for NGL products have required additional capital investments to increase the capacity of our infrastructure to bring these commodities from supply basins to market.  In response to this increased production and demand for NGL products, we are investing approximately $2.7 billion to $3.3 billion in new capital projects to meet the needs of oil and natural gas producers in the Bakken Shale, the Cana-Woodford Shale and the Granite Wash areas, and for additional NGL infrastructure in the Rockies, Mid-Continent and Gulf Coast regions that will enhance the distribution of NGL products to meet the increasing petrochemical industry and NGL export demand, which, when completed, are anticipated to provide additional earnings and cash flows.

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

Cash Distributions - During 2011, we paid cash distributions totaling $2.325 per unit, an increase of approximately 4.3 percent over the $2.23 per unit paid during 2010.  In January 2012, our general partner declared a cash distribution of $0.61 per unit ($2.44 per unit on an annualized basis), an increase of approximately 7.0 percent over the $0.57 declared in January 2011.

Debt Issuance and Maturity - In January 2011, we completed an underwritten public offering of $1.3 billion of senior notes, consisting of $650 million of 3.25-percent senior notes due 2016 and $650 million of 6.125-percent senior notes due 2041.  The net proceeds from the offering of approximately $1.28 billion were used to repay amounts outstanding under our commercial paper program, to repay the $225 million principal amount of senior notes in March 2011 and for general partnership purposes, including capital expenditures.

Unit Split - In July 2011, we completed a two-for-one split of our common and Class B units by a distribution of one unit for each unit outstanding and held by unitholders of record on June 30, 2011.  In July 2011, the Partnership Agreement was amended to adjust the formula for distributing available cash among our general partner and limited partners to reflect the unit split.  We have adjusted all unit and per-unit amounts contained herein to be presented on a post-split basis.

Partnership 2011 Credit Agreement - On August 1, 2011, we entered into the Partnership 2011 Credit Agreement, which replaced the Partnership Credit Agreement.
FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

The following table sets forth certain selected consolidated financial results for the periods indicated:

               
Variances
    
Variances
  
   
Years Ended December 31,
    
2011 vs. 2010
    
2010 vs. 2009
  
Financial Results
  
2011
    
2010
    
2009
    
Increase (Decrease)
    
Increase (Decrease)
  
   
(Millions of dollars)
  
Revenues
   $ 11,322.6     $ 8,675.9     $ 6,474.5     $ 2,646.7     31 %   $ 2,201.4     34 %
Cost of sales and fuel
     9,745.2       7,531.0       5,355.2       2,214.2     29 %     2,175.8     41 %
Net margin
     1,577.4       1,144.9       1,119.3       432.5     38 %     25.6     2 %
Operating costs
     459.4       403.5       411.3       55.9     14 %     (7.8 )   (2 %)
Depreciation and amortization
     177.5       173.7       164.1       3.8     2 %     9.6     6 %
Gain (loss) on sale of assets
     (1.0 )     18.6       2.7       (19.6 )   *       15.9     *  
Operating income
   $ 939.5     $ 586.3     $ 546.6     $ 353.2     60 %   $ 39.7     7 %
                                                     
Equity earnings from investments
   $ 127.2     $ 101.9     $ 72.7     $ 25.3     25 %   $ 29.2     40 %
Allowance for equity funds used
     during construction
   $ 2.3     $ 1.0     $ 26.9     $ 1.3     *     $ (25.9 )   (96 %)
Interest expense
   $ (223.1 )   $ (204.3 )   $ (206.0 )   $ 18.8     9 %   $ (1.7 )   (1 %)
Capital expenditures
   $ 1,063.4     $ 352.7     $ 615.7     $ 710.7     *     $ (263.0 )   (43 %)
* Percentage change is greater than 100 percent.
                                              
 
2011 vs. 2010 - NGL and condensate prices were higher while natural gas prices decreased during 2011, compared with 2010.  These changes in commodity prices had a direct impact on our revenues and cost of sales and fuel.
 
Operating income increased approximately 60 percent during 2011, compared with 2010.  The increase in operating income reflects higher net margin in our Natural Gas Liquids and Natural Gas Gathering and Processing segments.

Our Natural Gas Liquids segment benefited from more favorable NGL price differentials, as well as additional NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets.  Our Natural Gas Liquids segment also realized higher exchange service margins due primarily to higher NGL gathering and fractionation volumes and contract renegotiations at higher fees with our customers.  In addition, our Natural Gas Liquids segment realized higher isomerization margins resulting from wider price differentials between normal butane and iso-butane, and higher isomerization volumes.

Our Natural Gas Gathering and Processing segment benefited from significantly higher realized NGL and condensate prices, higher natural gas volumes processed and favorable changes in contract terms, offset partially by lower natural gas volumes gathered primarily in the Powder River Basin.

These increases were offset partially by the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method in our Natural Gas Liquids segment following the sale of a 49-percent ownership interest in Overland Pass Pipeline Company.  Additionally, our Natural Gas Pipelines segment realized lower transportation margins due to narrower natural gas price location differentials that caused a reduction in contracted capacity primarily on Midwestern Gas Transmission.

Gain (loss) on sale of assets decreased from 2010, which reflected a $16.3 million gain on the sale of a 49-percent interest of Overland Pass Pipeline Company.

Operating costs increased for 2011, compared with 2010, due primarily to higher labor and employee-related costs associated with incentive and benefit plans, and higher ad valorem taxes, as well as higher materials and outside services expenses associated primarily with scheduled maintenance at our natural gas liquids fractionation and storage facilities.  Our employees participate in compensation and benefit plans administered by ONEOK, which include ONEOK’s short-term incentive and share-based compensation plans.  ONEOK’s share price significantly increased in 2011, resulting in increased employee-related costs to us.

Equity earnings from investments increased for 2011, compared with 2010, due to the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company in our Natural Gas Liquids segment and increased contracted capacity on Northern Border Pipeline in our Natural Gas Pipeline segment.
Capital expenditures increased for 2011, compared with 2010, due primarily to growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and the purchase of leased equipment at our Bushton plant.

2010 vs. 2009 - Energy markets were affected by higher commodity prices during 2010, compared with 2009.  The increase in commodity prices had a direct impact on our revenues and cost of sales and fuel.   We completed more than $2.0 billion in growth projects at the end of 2008 and in 2009.  Our 2010 operating results include the benefits from a full year of our completed projects, including the following projects placed in service in 2009:
·  
February - Guardian Pipeline’s expansion and extension project in our Natural Gas Pipelines segment;
·  
March - Grasslands natural gas processing plant expansion in our Natural Gas Gathering and Processing segment;
·  
March - D-J Basin lateral pipeline in our Natural Gas Liquids segment;
·  
July - Arbuckle Pipeline in our Natural Gas Liquids segment; and
·  
October - Piceance lateral pipeline in our Natural Gas Liquids segment.

Operating income increased 7 percent in 2010, compared with 2009.  The increase in operating income for the 2010 period reflects the benefit of a full year of operations of our capital projects completed in 2009, resulting in higher NGL volumes in the Natural Gas Liquids segment; higher contracted natural gas transportation capacity on the Midwestern Gas Transmission and Viking Gas Transmission pipelines in the Natural Gas Pipelines segment; and an increase in Williston Basin volumes in our Natural Gas Gathering and Processing segment.  Additionally, our Natural Gas Liquids and Natural Gas Pipelines segments produced higher storage margins, primarily as a result of contract renegotiations.  Operating income also included the gain on the sale of a 49-percent ownership interest in Overland Pass Pipeline Company.  Operating income also benefited from lower than estimated ad valorem taxes associated with our capital projects completed in 2009 and lower outside services costs for maintenance at our fractionators in 2009, offset partially by incremental employee-related costs and property insurance costs associated with our capital projects completed in 2009.

These increases were offset partially by lower optimization margins in the Natural Gas Liquids segment due to limited NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf Coast  NGL market centers until September 2010 and less favorable NGL price differentials; and decreased margins in our Natural Gas Gathering and Processing segment from lower natural gas volumes processed and sold in western Oklahoma and Kansas, selling our bankruptcy claims with Lehman Brothers in 2009 and lower natural gas volumes gathered in the Powder River Basin in Wyoming.

Equity earnings from investments increased due primarily to increased contracted capacity on Northern Border Pipeline due to wider natural gas price differentials.  Additionally, in September 2010, we began accounting for our 50-percent investment in Overland Pass Pipeline Company, which includes the Overland Pass Pipeline and the D-J Basin and Piceance lateral pipelines, as an equity investment.

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 approximately $950 million to $1.1 billion in growth projects in the Williston Basin and Cana-Woodford Shale areas that will enable us to meet the rapidly growing needs of crude oil and natural gas producers in those areas.

Williston Basin Processing Plants and related projects - Our projects in this basin include three 100 MMcf/d natural gas processing facilities:  the Garden Creek plant in eastern McKenzie County, North Dakota, and the Stateline I and II plants in western Williams County, North Dakota.  We have multi-year supply commitments and acreage dedications for all the capacity of the Garden Creek and Stateline I plants and for approximately 75 percent of the Stateline II plant’s capacity.  In addition, we will expand and upgrade our existing gathering and compression infrastructure and add new well connections associated with these plants.  The Garden Creek plant, which was placed in service in December 2011, and related infrastructure projects are expected to cost approximately $350 million to $415 million, excluding AFUDC.  The Stateline I plant, which is expected to be in service by the third quarter of 2012, and related infrastructure projects are expected to cost approximately $300 million to $355 million, excluding AFUDC.  The Stateline II plant, which is expected to be in service during the first half of 2013, and related infrastructure projects are expected to cost approximately $260 million to $305 million, excluding AFUDC.

Horizontal wells drilled in the Williston Basin are economically justified by producers primarily by crude oil economics.  In addition, we expect our commodity price exposure to increase, particularly to NGLs and natural gas, as our equity volumes increase under our POP contracts with our customers in the Williston Basin.
Cana-Woodford Shale projects - In 2010, we completed projects totaling approximately $38 million in the Cana-Woodford Shale development in Oklahoma, which included the connection of our western Oklahoma natural gas gathering system to our Maysville natural gas processing facility in central Oklahoma, as well as new well connections to gather and process additional Cana-Woodford Shale natural gas volumes.

In both the Williston Basin and Cana Woodford Shale project areas, nearly all of the new gas production is from horizontally drilled and completed wells.  These wells tend to produce at higher initial volumes; however, they generally have higher initial decline rates than conventional vertical wells, but the decline curves flatten out.  These wells are expected to have long-lasting reserves.  The routine growth capital needed to connect to new wells and expand our infrastructure is expected to increase compared with our previous experience.

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

Selected Financial Results - 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,
    
2011 vs. 2010
    
2010 vs. 2009
  
Financial Results
  
2011
    
2010
    
2009
    
Increase (Decrease)
    
Increase (Decrease)
  
   
(Millions of dollars)
  
NGL and condensate sales
   $ 917.5     $ 722.6     $ 578.5     $ 194.9     27 %   $ 144.1     25 %
Residue gas sales
     461.5       446.9       363.0       14.6     3 %     83.9     23 %
Gathering, compression, dehydration
  and processing fees and other revenue
     154.5       148.4       153.1       6.1     4 %     (4.7 )   (3 %)
Cost of sales and fuel
     1,130.6       966.5       734.6       164.1     17 %     231.9     32 %
Net margin
     402.9       351.4       360.0       51.5     15 %     (8.6 )   (2 %)
Operating costs
     153.7       136.8       135.1       16.9     12 %     1.7     1 %
Depreciation and amortization
     68.3       60.7       59.3       7.6     13 %     1.4     2 %
Gain (loss) on sale of assets
     (0.3 )     (0.3 )     2.8       -     -       (3.1 )   *  
Operating income
   $ 180.6     $ 153.6     $ 168.4     $ 27.0     18 %   $ (14.8 )   (9 %)
                                                     
Equity earnings from investments
   $ 30.5     $ 27.5     $ 28.4     $ 3.0     11 %   $ (0.9 )   (3 %)
Capital expenditures
   $ 623.7     $ 216.0     $ 105.5     $ 407.7     *     $ 110.5     *  
* Percentage change is greater than 100 percent.
                                              

2011 vs. 2010 - Net margin increased primarily as a result of the following:
·  
an increase of $32.6 million due to higher net realized NGL and condensate prices;
·  
an increase of $19.4 million due to higher natural gas volumes processed in the Williston Basin and western Oklahoma resulting from increased drilling activity, offsetting reduced drilling activity in certain parts of Kansas and weather-related outages in the first quarter of 2011;
·  
an increase of $8.8 million due to favorable changes in contract terms; and offset partially by
·  
a decrease of $8.2 million due to lower natural gas volumes gathered as a result of continued production declines and reduced drilling activity by producers in the Powder River Basin.

Operating costs increased due primarily to the following:
·  
an increase of $11.9 million of higher labor costs and employee-related costs associated with incentive and benefit plans; and
·  
an increase of $7.2 million in chemicals, material, supplies and outside services associated with the growth of our operations; offset partially by
·  
a reduction of $4.7 million in rental costs due to the termination of our Processing and Services Agreement with ONEOK when we acquired the previously leased equipment at the Bushton Plant in June 2011.

Depreciation and amortization increased due to both the completion of the connection of our western Oklahoma natural gas gathering system to our Maysville natural gas processing facility in central Oklahoma and the completion of well connections and infrastructure projects supporting our volume growth in the Williston Basin.

Capital expenditures increased due primarily to our growth projects discussed above and the completion of approximately 600 well connections in the Williston Basin and Mid-Continent areas in 2011, compared with approximately 300 well connections in 2010.

We expect capital expenditures to increase in 2012 as construction continues on our growth projects.  See “Capital Expenditures” in “Liquidity and Capital Resources” for additional detail of our projected capital expenditures.
2010 vs. 2009 - Net margin decreased primarily as a result of the following:
·  
a decrease of $7.8 million due to lower natural gas volumes processe
d and sold in western Oklahoma and Kansas as a result of natural production declines, operational outages and a period of ethane rejection;
·  
a decrease of $6.5 million from selling our Lehman Brothers bankruptcy claims in 2009;
·  
a decrease of $6.3 million due to lower natural gas volumes gathered as a result of natural production declines and reduced drilling activity by our customers in the Powder River Basin; offset partially by
·  
an increase of $9.1 million due to higher natural gas volumes gathered and processed in the Williston Basin, primarily due to the increased drilling activity in the Bakken Shale;
·  
an increase of $3.5 million due to a favorable contract settlement in the third quarter 2010 and other changes in contract terms.

Capital expenditures increased due primarily to capital projects in the Williston Basin.

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)
  
2011
    
2010
    
2009
  
Natural gas gathered (BBtu/d)
     1,030       1,067       1,123  
Natural gas processed (BBtu/d) (b)
     713       674       658  
NGL sales (MBbl/d)
     48       44       43  
Residue gas sales (BBtu/d)
     317       286       291  
Realized composite NGL net sales price ($/gallon) (c)
   $ 1.08     $ 0.94     $ 0.90  
Realized condensate net sales price ($/Bbl) (c)
   $ 82.56     $ 63.81     $ 78.35  
Realized residue gas net sales price ($/MMBtu) (c)
   $ 5.47     $ 5.58     $ 3.55  
Realized gross processing spread ($/MMBtu) (c)
   $ 8.17     $ 6.41     $ 6.63  
(a) - Includes volumes for consolidated entities only.
                        
(b) - Includes volumes processed at company-owned and third-party facilities.
          
(c) - Presented net of the impact of hedging activities and includes equity volumes only.
  
 
Natural gas gathered decreased for each of the comparable periods due to continued production declines and reduced drilling activity, primarily in the Powder River Basin in Wyoming and certain parts of Kansas, and weather-related outages in the first quarter of 2011, offset partially by increased drilling activity in the Williston Basin and western Oklahoma.

Natural gas processed and residue gas sales increased for each of the comparable periods due to an increase in drilling activity in the Williston Basin, offsetting reduced drilling activity and natural production declines in Kansas, and reduced drilling activity in certain parts of western Oklahoma and weather-related outages in the first quarter of 2011.
 
   
Years Ended December 31,
  
Operating Information (a)
  
2011
    
2010
    
2009
  
Percent of proceeds
                  
  NGL sales (Bbl/d)
     6,472       6,310       5,472  
  Residue gas sales (MMBtu/d)
     48,198       41,813       41,768  
  Condensate sales (Bbl/d)
     1,684       1,763       1,735  
  Percentage of total net margin
     61 %     54 %     50 %
Fee-based
                        
  Wellhead volumes (MMBtu/d)
     1,030,045       1,067,090       1,122,861  
  Average rate ($/MMBtu)
   $ 0.34     $ 0.31     $ 0.30  
  Percentage of total net margin
     32 %     35 %     35 %
Keep-whole
                        
  NGL shrink (MMBtu/d) (b)
     10,131       13,545       17,400  
  Plant fuel (MMBtu/d) (b)
     1,104       1,648       2,031  
  Condensate shrink (MMBtu/d) (b)
     1,082       1,433       1,727  
  Condensate sales (Bbl/d)
     219       290       349  
  Percentage of total net margin
     7 %     11 %     15 %
(a) - Includes volumes for consolidated entities only.
                        
(b) - Refers to the Btus that are removed from natural gas through processing.
          
Commodity Price Risk - Our Natural Gas Gathering and Processing segment is exposed to commodity price risk as a result of receiving commodities in exchange for our services.  A small percentage of our services, based on volume, are provided through keep-whole contracts.  See discussion regarding our commodity price risk beginning on page 60 under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk.

Natural Gas Pipelines

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Pipelines segment for the periods indicated:
               
Variances
    
Variances
  
   
Years Ended December 31,
    
2011 vs. 2010
    
2010 vs. 2009
  
Financial Results
  
2011
    
2010
    
2009
    
Increase (Decrease)
    
Increase (Decrease)
  
   
(Millions of dollars)
  
Transportation revenues
   $ 233.6     $ 244.2     $ 230.6     $ (10.6 )     (4 %)   $ 13.6       6 %
Storage revenues
     68.8       67.8       62.1       1.0       1 %     5.7       9 %
Gas sales and other revenues
     35.4       39.1       50.1       (3.7 )     (9 %)     (11.0 )     (22 %)
Cost of sales
     53.4       50.9       57.0       2.5       5 %     (6.1 )     (11 %)
Net margin
     284.4       300.2       285.8       (15.8 )     (5 %)     14.4       5 %
Operating costs
     108.6       96.5       96.1       12.1       13 %     0.4       0 %
Depreciation and amortization
     45.4       44.1       43.7       1.3       3 %     0.4       1 %
Gain (loss) on sale of assets
     (0.3 )     3.4       (0.7 )     (3.7 )     *       4.1       *  
Operating income
   $ 130.1     $ 163.0     $ 145.3     $ (32.9 )     (20 %)   $ 17.7       12 %
                                                         
Equity earnings from investments
   $ 76.9     $ 68.8     $ 41.9     $ 8.1       12 %   $ 26.9       64 %
Capital expenditures
   $ 37.8     $ 27.6     $ 62.2     $ 10.2       37 %   $ (34.6 )     (56 %)
* Percentage change is greater than 100 percent.
                                                  

2011 vs. 2010 - Net margin decreased primarily as a result of the following:
·  
a decrease of $12.5 million from lower natural gas transportation margins due to narrower natural gas price location differentials that decreased contracted transportation capacity primarily on Midwestern Gas Transmission and interruptible transportation volumes across our pipelines; and
·  
a decrease of $5.0 million due primarily to lower realized prices on our retained fuel positions.

Operating costs increased primarily as a result of the following:
·  
an increase of $6.7 million due to higher labor costs and employee-related costs associated with incentive and benefit plans; and
·  
an increase of $1.4 million due to higher ad valorem taxes associated with our completed capital projects.

Equity earnings from investments increased due primarily to increased contracted capacity on Northern Border Pipeline resulting from wider natural gas price location differentials between the markets it serves.  Substantially all of Northern Border Pipeline’s long-haul capacity has been contracted through March 2013.

2010 vs. 2009 - Net margin increased primarily as a result of the following:
·  
an increase of $8.7 million from higher natural gas transportation margins, excluding retained fuel, primarily as a result of increased capacity contracted on Midwestern Gas Transmission due to a new interconnection with the Rockies Express Pipeline that was placed in service beginning in June 2009; Viking Gas Transmission’s Fargo lateral that was completed in October 2009; and the incremental margin from the Guardian Pipeline expansion and extension project that was completed in February 2009; and
·  
an increase of $3.5 million from higher natural gas storage margins, excluding retained fuel, primarily as a result of contract renegotiations.

Equity earnings from investments increased due primarily to increased contracted capacity on Northern Border Pipeline due to wider natural gas price differentials.

Capital expenditures decreased due primarily to the completion of our capital projects in 2009, including the completion of the Guardian Pipeline extension and expansion, Viking Gas Transmission’s Fargo lateral and Midwestern Gas Transmission’s interconnect with the Rockies Express Pipeline.
   
Years Ended December 31,
  
Operating Information (a)
  
2011
    
2010
    
2009
  
Natural gas transportation capacity contracted (MDth/d)
     5,373       5,616       5,507  
Transportation capacity subscribed
     83 %     87 %     86 %
Average natural gas price
                        
Mid-Continent region  ($/MMBtu)
   $ 3.88     $ 4.17     $ 3.28  
(a) - Includes volumes for consolidated entities only.
                        
 
2011 vs. 2010 - Natural gas transportation capacity contracted decreased due primarily to lower subscribed capacity on Midwestern Gas Transmission due to narrower natural gas price location differentials between the markets it serves.

2010 vs. 2009 - Natural gas transportation capacity contracted increased due primarily to increased capacity on Midwestern Gas Transmission due to a new interconnection with the Rockies Express Pipeline, Viking Gas Transmission’s Fargo lateral, and Guardian Pipeline expansion projects completed in 2009.

Our pipelines primarily serve end-users, such as natural gas distribution companies and electric-generation companies, that require natural gas to operate their businesses regardless of location price differentials.  The development of shale gas and other resource plays has continued to increase available natural gas supply and has caused natural gas prices to decrease and location and seasonal price differentials to narrow.  As additional supply is developed, we expect producers to demand incremental services in the future to transport their production to market.  The abundance of shale gas supply and new regulations on emissions from coal-fired electric-generation plants may also increase the demand for our services from electric-generation companies if they were to convert to a natural gas fuel source.  Conversely, contracted capacity by certain customers that are focused on capturing location or seasonal price differentials may decrease in the future due to narrowing price differentials.  Overall, we expect our fee-based earnings to remain relatively stable in the future as the development of shale and other resource plays continue.

Natural Gas Liquids

Growth Projects - Our growth strategy in the Natural Gas Liquids segment is focused around the oil and natural gas drilling activity in shale and other resource plays from the Rockies through the Mid-Continent region into Texas.  Increasing natural gas and NGL production resulting from this activity and higher petrochemical industry demand for NGL products have required additional capital investments to increase the capacity of 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 over the next five years and international demand for propane is expected to impact the NGL market in the future.  Our Natural Gas Liquids segment is investing approximately $1.7 billion to $2.2 billion through 2014.  This investment will accommodate the gathering and fractionation of growing NGL supplies from the shale and other resource plays across our asset base and alleviate infrastructure constraints between the Mid-Continent and Texas Gulf Coast regions to meet the increasing petrochemical industry and NGL export demand in the Gulf Coast. The execution of these capital investments aligns with our focus to grow fee-based earnings.  Our supply commitments from producers and natural gas processors associated with our growth projects will provide incremental and long-term fee-based earnings to our exchange services business.  Over time, these growing fee-based volumes will fill a portion of the capacity used in 2011 to capture the price differentials between the two market centers.  In addition, we believe the price differentials between the Mid-Continent and Gulf Coast market centers will narrow over the long-term as new fractionators and pipelines, including our MB-2 fractionator and Sterling III pipeline, begin to alleviate constraints impacting NGL prices and the location price differential between the two market centers.

Sterling III Pipeline - We plan to build a 570-plus-mile natural gas liquids pipeline, the Sterling III Pipeline, which will have the flexibility to transport either unfractionated NGLs or NGL products from the Mid-Continent to the Texas Gulf Coast.  The Sterling III Pipeline will traverse the NGL-rich Woodford Shale that is currently under development, as well as provide transportation capacity for the growing NGL production from the Cana-Woodford Shale and Granite Wash areas, where the pipeline can gather unfractionated NGLs from the new natural gas processing plants that are being built as a result of increased drilling activity in these areas.  The Sterling III Pipeline will have an initial capacity to transport up to 193 MBbl/d of production from our natural gas liquids infrastructure at Medford, Oklahoma, to our storage and fractionation facilities in Mont Belvieu, Texas.  We have multi-year supply commitments from producers and natural gas processors for approximately 75 percent of the pipeline’s capacity.  Additional pump stations could expand the capacity of the pipeline to 250 MBbl/d.  Following the receipt of all necessary permits and the acquisition of rights-of-way, construction is scheduled to begin in 2013, with an expected completion late the same year.
The investment also includes reconfiguring our existing Sterling I and II Pipelines, which currently distribute NGL products between the Mid-Continent and Gulf Coast NGL market centers, to transport either unfractionated NGLs or NGL products.

The project costs for the new pipeline and reconfiguring projects are estimated to be $610 million to $810 million, excluding AFUDC.

MB-2 fractionator - We plan to construct a new 75-MBbl/d fractionator, MB-2, near our storage facility in Mont Belvieu, Texas.  The Texas Commission on Environmental Quality (TCEQ) has approved our permit application to build this fractionator.  Construction of the MB-2 fractionator began in June 2011 and is expected to be completed in mid-2013.  The cost of the MB-2 fractionator is estimated to be $300 million to $390 million, excluding AFUDC.  We have multi-year supply commitments from producers and natural gas processors for all of the fractionator’s capacity.  The fractionator can be expanded to 125 MBbl/d to accommodate additional NGL volumes from the Arbuckle Pipeline and the Sterling I, II and III pipelines.

Bakken Pipeline and related projects - We plan to build a 525- to 615-mile natural gas liquids pipeline, the Bakken Pipeline, to transport unfractionated NGLs from the Williston Basin to the Overland Pass Pipeline.  The Bakken Pipeline initially will have the capacity to transport up to 60 MBbl/d of unfractionated NGL production and can be expanded to 110 MBbl/d with additional pump stations.  The unfractionated NGLs then will be delivered to our existing natural gas liquids fractionation and distribution infrastructure in the Mid-Continent.  Project costs for the new pipeline are estimated to be $450 million to $550 million, excluding AFUDC.

NGL supply commitments for the Bakken Pipeline will be anchored by NGL production from the Partnership’s natural gas processing plants in the Williston Basin.  Following receipt of all necessary permits, construction of the 12-inch diameter pipeline is expected to begin in the second quarter of 2012 and be in service during the first half of 2013.

The unfractionated NGLs from the Bakken Pipeline and other supply sources under development in the Rockies will require installing additional pump stations and expanding existing pump stations on the Overland Pass Pipeline, in which we own a 50-percent equity interest.  These additions and expansions will increase the capacity of Overland Pass Pipeline to 255 MBbl/d.  Our anticipated share of the costs for this project is estimated to be $35 million to $40 million, excluding AFUDC.

Bushton Fractionator Expansion - To accommodate the additional volume from the Bakken Pipeline, we are investing $110 million to $140 million, excluding AFUDC, to expand and upgrade our existing fractionation capacity at Bushton, Kansas, increasing our capacity to 210 MBbl/d from 150 MBbl/d.  This project is expected to be in service during the fourth quarter of 2012.

Cana-Woodford Shale and Granite Wash projects - We plan to invest approximately $197 million to $257 million, excluding AFUDC, in our existing Mid-Continent infrastructure, primarily in the Cana-Woodford Shale and Granite Wash areas. These investments will expand our ability to transport unfractionated NGLs from these Mid-Continent supply areas to fractionation facilities in Oklahoma and Texas and distribute NGL products to the Mid-Continent, Gulf Coast and upper Midwest market centers.

These investments include constructing more than 230 miles of natural gas liquids pipelines that will expand our existing Mid-Continent natural gas liquids gathering system in the Cana-Woodford Shale and Granite Wash areas.  The pipelines will connect to three new third-party natural gas processing facilities that are under construction and to three existing third-party natural gas processing facilities that are being expanded.  Additionally, we will install additional pump stations on our Arbuckle Pipeline to increase its capacity to 240 MBbl/d.  When completed, these projects are expected to add, through multi-year supply contracts, approximately 75 to 80 MBbl/d of unfractionated NGLs, to our existing natural gas liquids gathering systems.  These projects are expected to be completed early in the second quarter of 2012 and cost approximately $180 million to $240 million, excluding AFUDC.

In 2010, we invested approximately $17 million to increase the accessibility of new NGL supply to our Arbuckle Pipeline and Mont Belvieu fractionation facilities.

Sterling I Pipeline Expansion - In 2011, we installed seven additional pump stations at a cost of approximately $30 million, excluding AFUDC, along our existing Sterling I natural gas liquids distribution pipeline, increasing its capacity by 15 MBbl/d, which is supplied by our Mid-Continent natural gas liquids infrastructure.  The Sterling I pipeline transports NGL products from our fractionator in Medford, Oklahoma, to the Mont Belvieu, Texas, market center.
For a discussion of our capital expenditure financing, see “Capital Expenditures” in “Liquidity and Capital Resources.”

Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids segment for the periods indicated:
 
               
Variances
    
Variances
  
 
Years Ended December 31,
    
2011 vs. 2010
    
2010 vs. 2009
  
Financial Results
  
2011
    
2010
    
2009
    
Increase (Decrease)
    
Increase (Decrease)
  
   
(Millions of dollars)
  
NGL and condensate sales
   $ 9,764.2     $ 7,219.0     $ 4,962.2     $ 2,545.2       35 %   $ 2,256.8       45 %
Exchange service and storage revenues
     531.6       470.9       365.1       60.7       13 %     105.8       29 %
Transportation revenues
     65.5       85.1       94.4       (19.6 )     (23 %)     (9.3 )     (10 %)
Cost of sales and fuel
     9,469.5       7,275.4       4,945.3       2,194.1       30 %     2,330.1       47 %
Net margin
     891.8       499.6       476.4       392.2       79 %     23.2       5 %
Operating costs
     198.9       173.9       182.2       25.0       14 %     (8.3 )     (5 %)
Depreciation and amortization
     63.9       68.9       61.2       (5.0 )     (7 %)     7.7       13 %
Gain (loss) on sale of assets
     (0.4 )     15.5       (0.2 )     (15.9 )     *       15.7       *  
Operating income
   $ 628.6     $ 272.3     $ 232.8     $ 356.3       *     $ 39.5       17 %
                                                         
Equity earnings from investments
   $ 19.9     $ 5.6     $ 2.5     $ 14.3       *     $ 3.1       *  
Allowance for equity funds used
                                                        
during construction
   $ 2.1     $ 0.9     $ 25.3     $ 1.2       *     $ (24.4 )     (96 %)
Capital expenditures
   $ 401.3     $ 107.9     $ 446.9     $ 293.4       *     $ (339.0 )     (76 %)
* Percentage change is greater than 100 percent.
                                                  
 
2011 vs. 2010 - NGL prices and price differentials between Conway, Kansas, and Mont Belvieu, Texas, were wider during 2011, compared with 2010.  The increase in NGL prices and differentials had a significant impact on our revenues and cost of sales and fuel.

Net margin increased primarily as a result of the following:
·  
an increase of $363.6 million in optimization and marketing margins due primarily to the following:
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an increase of $335.2 million from more favorable NGL price differentials and additional fractionation and transportation capacity available for optimization activities between the Conway, Kansas, and Mont Belvieu, Texas, NGL market centers; and
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an increase of $28.4 million from higher marketing volumes and more favorable margins on NGL products marketed;
·  
an increase of $32.5 million related to higher NGL volumes gathered and fractionated in Texas and the Mid-Continent and Rocky Mountain regions, excluding the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, and contract renegotiations for higher fees associated with our NGL exchange services activities, offset partially by higher costs associated with NGL volumes fractionated by third parties;
·  
an increase of $26.4 million related to higher isomerization margins resulting from wider price differentials between normal butane and iso-butane, and higher isomerization volumes; and
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an increase of $12.4 million due to higher storage margins as a result of contract renegotiations at higher fees; offset partially by
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a decrease of $42.8 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.
 
Operating costs increased primarily as a result of the following:
·  
an increase of $17.1 million due to higher labor costs and employee-related costs associated with incentive and benefit plans, which includes higher equity-based compensation costs;
·  
an increase of $9.4 million from higher materials and outside services expenses associated primarily with scheduled maintenance at our fractionation, pipeline and storage facilities; and
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an increase of $3.6 million from higher ad valorem taxes as a result of our completed capital projects; offset partially by
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a decrease of $5.4 million due to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.
Depreciation and amortization expense decreased due primarily to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method, offset partially by depreciation associated with our completed capital projects.

Equity earnings increased due primarily to the deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method.

Gain (loss) on sale of assets decreased due primarily to the $16.3 million gain on sale of a 49-percent ownership interest in Overland Pass Pipeline Company recorded in 2010.

Capital expenditures increased due primarily to the purchase of leased equipment at our Bushton Plant and expenditures related to our growth projects discussed above.

Previously, we had a Processing and Services Agreement with ONEOK and OBPI, under which we contracted for all of OBPI’s rights, including all of the capacity of the Bushton Plant, reimbursing OBPI for all costs associated with the operation and maintenance of the Bushton Plant and its obligations under equipment leases covering portions of the Bushton Plant.  In April 2011, pursuant to our rights under the Processing and Services Agreement, we directed OBPI to give notice of intent to exercise the purchase option for the leased equipment pursuant to the terms of the equipment leases.  On June 30, 2011, we acquired OBPI, and OBPI closed the purchase option and terminated the equipment lease agreements.  The amount paid by us to complete the transactions was approximately $94.2 million, which included the reimbursement to ONEOK of obligations related to the Processing and Services Agreement.
 
2010 vs. 2009 - Net margin increased primarily as a result of the following:
·  
an increase of $51.4 million due to increased NGL volumes gathered, fractionated and transported, primarily associated with the completion of the Arbuckle Pipeline and Piceance and D-J Basin lateral pipelines, as well as new supply connections; and
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an increase of $10.9 million due to higher NGL storage margins as a result of contract renegotiations; offset partially by
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a decrease of $34.7 million related to lower optimization margins due to limited fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf Coast NGL market centers until September 2010 and less favorable NGL price differentials; and
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a decrease of $4.4 million due to the impact of operational measurement gains and losses in 2010.

Operating costs decreased due primarily to the following:
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a decrease of $8.2 million resulting from lower than estimated ad valorem taxes associated with our capital projects completed in 2009;
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a decrease of $3.4 million in outside services costs attributable primarily to maintenance projects at our fractionators in 2009; offset partially by
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an increase of $2.3 million in property insurance costs related to increased coverage for our assets; and
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an increase of $1.4 million due primarily to increased employee labor costs resulting from the operations of our capital projects completed in 2009.

Depreciation and amortization increased due primarily to higher depreciation expense associated with our capital projects completed in 2009.

Gain (loss) on sale of assets increased due primarily to the sale of a 49-percent ownership interest in Overland Pass Pipeline Company in September 2010.

Equity earnings from investments increased due primarily to the deconsolidation of Overland Pass Pipeline Company in September 2010.
Allowance for equity funds used during construction and capital expenditures decreased due primarily to the completion of our capital projects in 2009.
 
   
Years Ended December 31,
  
Operating Information
  
2011
    
2010
    
2009
  
NGL sales (MBbl/d)
     497       457       408  
NGLs fractionated (MBbl/d) (a)
     537       512       481  
NGLs transported-gathering lines (MBbl/d) (b) (c)
     436       440       372  
NGLs transported-distribution lines (MBbl/d) (b)
     473       468       459  
Conway-to-Mont Belvieu OPIS average price differential
                  
  Ethane ($/gallon)
   $ 0.28