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ONEOK Partners LP 10-K 2010 Documents found in this filing: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, 2009.
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)
Registrant’s
telephone number, including area code (918) 588-7000
Securities
registered pursuant to Section 12(b) of the Act:
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 Web site, 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 __ 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, 2009, was $2.7 billion.
Indicate
the number of shares outstanding of each of the registrant’s classes of common
stock, as of the latest practicable date.
DOCUMENTS
INCORPORATED BY REFERENCE: >None.
ONEOK PARTNERS, L.P.
2009
ANNUAL REPORT
As used
in this Annual Report, references to “we,” “our,” “us” or the “Partnership”
refers 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:
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.
PART I
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. We also own a 50 percent equity interest in a leading
transporter of natural gas imported from Canada into the United
States.
DESCRIPTION
OF BUSINESS
Partnership
Structure
We are
managed under the direction of the Board of Directors of our sole general
partner, ONEOK Partners GP, which consists of 10 members. Seven of
our Board members qualify as independent under the listing standards of the NYSE
and also serve as the Audit Committee of ONEOK Partners GP. Four of
our independent directors serve on the Conflicts Committee.
ONEOK
Partners GP is a wholly owned subsidiary of ONEOK. Three of our
members that are independent under NYSE listing standards 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. As of December 31, 2009, ONEOK
and its subsidiaries owned a 45.1 percent aggregate equity interest in
us. 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.
Business
Strategy
Our
primary business strategy is to increase distributable cash flow through
consistent earnings growth while focusing on safe, reliable, environmentally
responsible and legally compliant operations for our customers, employees,
contractors and the public through the following:
Outlook
We expect
a moderate economic recovery in 2010, with inflationary pressures beginning in
2011. Although recent volatility in the financial markets could limit
our access to financial markets on a timely basis or increase our cost of
capital in the future, we anticipate improved credit markets during 2010,
compared with 2009; however, inflation risk may increase the cost of
capital. We anticipate the consolidation of underperforming assets in
the industry, particularly those with high commodity price exposure and/or high
levels of debt. Additionally, we anticipate an improving commodity
price environment during 2010, compared with 2009.
We intend
to pursue growth in our natural gas businesses through well connections and
contract renegotiations and through new plant construction, expansions and
extensions of our existing systems and plants. For our natural gas liquids
business, we intend to continue to focus on adding new supply connections and
expanding our existing assets. We plan to spend approximately $362 million
on capital expenditures in 2010, of which approximately $278 million is expected
to be for growth projects. We may also pursue strategic acquisitions
related to gathering, processing, fractionating, storing, transporting or
marketing natural gas and NGLs.
SIGNIFICANT
DEVELOPMENTS
For
further discussion on these projects, see “Capital Projects” beginning on page
37.
Equity Issuances> - In July
2009, we completed an underwritten public offering of 5,486,690 common units,
including the partial exercise by the underwriters of their over-allotment
option, at $45.81 per common unit, generating net proceeds of approximately
$241.6 million. In conjunction with the offering, ONEOK Partners GP
contributed an aggregate of $5.1 million in order to maintain its 2 percent
general partner interest in us. We used the proceeds from the sale of
common units and the general partner contributions to repay borrowings under our
Partnership Credit Agreement and for general partnership purposes.
In
February 2010, we completed an underwritten public offering of 5,500,900 common
units, including the partial exercise by the underwriters of their
over-allotment option, at $60.75 per common unit, generating net proceeds of
approximately $322.6 million. In conjunction with the offering, ONEOK
Partners GP contributed $6.8 million in order to maintain its 2 percent general
partner interest in us. We used the proceeds from the sale of common units
and the general partner contribution to repay borrowings under our Partnership
Credit Agreement and for general partnership purposes. As a result of
these transactions, ONEOK and its subsidiaries own a 42.8 percent aggregate
equity interest in us.
SEGMENT
FINANCIAL INFORMATION
We
implemented changes to the structure of our previous reportable business
segments during the third quarter of 2009 to better align them with how we
manage our businesses. Our financial results are now reported in
these three reportable business segments: (i) Natural Gas Gathering and
Processing; (ii) Natural Gas Pipelines, both of which remain unchanged; and
(iii) Natural Gas Liquids, which consolidates our former natural gas liquids
gathering and fractionation segment with our former natural gas liquids
pipelines segment, due to the integrated manner in which they are
managed. Prior-period amounts have been recast to reflect these
segment changes.
See Note
M of the Notes to Consolidated Financial Statements in this Annual Report for
additional information about intersegment revenues.
NARRATIVE
DESCRIPTION OF BUSINESS
Natural
Gas Gathering and Processing
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 generally in the form of a mixed, unfractionated NGL stream. This
unfractionated NGL stream is shipped to fractionators where, through the
application of heat and pressure, the unfractionated NGL stream is separated
into NGL products. Our natural gas and NGL products are sold to
affiliates and a diverse customer base.
Our
natural gas processing operations utilize straddle and field gas processing
plants to extract NGLs and remove water vapor and other contaminants from the
unprocessed natural gas stream. A straddle gas processing plant is
situated on a pipeline system and relies on the pipeline’s natural gas
throughput volume, which subjects the plant to increased supply risk as it is
dependent upon the throughput of a single pipeline rather than several supply
sources. Field gas processing plants process natural gas gathered
from multiple producing wells.
We
generally gather and process gas under the following types of
contracts.
Revenues
of this segment are derived primarily from fee and POP contracts. 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
sold.
See Note
N of the Notes to Consolidated Financial Statements in this Annual Report for
additional discussion of unconsolidated affiliates.
In the
Mid-Continent region, our gathering and processing assets in the Anadarko Basin
of Oklahoma and the Hugoton and Central Kansas Uplift Basins of Kansas are well
established. We anticipate continuing volumetric declines in most
non-shale wells that supply our gathering and processing operations; however, we
expect this to be more than offset by the increased drilling activity in the
Cana Woodford Shale area of Western Oklahoma, in which we have a substantial
gathering position.
In the
Rocky Mountain region, we have seen declines in gathered volumes in the Powder
River Basin; however, our Williston Basin volumes are growing as drilling
activity increases, primarily driven by producer development of Bakken Shale oil
wells, which also produce natural gas containing significant NGLs.
Demand - Demand for gathering
and processing services is typically aligned with the production of natural
gas. Our 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 market
conditions. Storage injection and withdrawal rates, as well as
available storage capacity, can also have an impact on commodity
prices. We are exposed to commodity price risk as a result of
receiving commodities in exchange for our services. To a lesser
extent, exposures arise from the gross processing spread with respect to our
keep-whole processing contracts. We are also exposed to the risk of
price fluctuations and the cost of transportation at various market locations,
and the demand for our products by the petrochemical industry and other
consumers.
Seasonality - Some 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 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 gathering and
processing business remains relatively fragmented despite significant
consolidation in the industry. We compete for natural gas supplies
with 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:
We are
responding to these industry conditions by making capital investments to improve
natural gas processing efficiency and reduce operating costs, evaluating
consolidation opportunities to maximize earnings, selling assets in non-core
operating areas and renegotiating unprofitable contracts. The
principal goal of the contract renegotiation effort is to eliminate unprofitable
contracts and improve margins, primarily during periods when the gross
processing spread is negative.
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
Our
interstate natural gas pipeline assets transport natural gas through
FERC-regulated interstate natural gas pipelines in North Dakota, Minnesota,
Wisconsin, Illinois, Indiana, Kentucky, Tennessee, Oklahoma, Texas and New
Mexico. Our interstate pipelines include:
Our
intrastate natural gas pipeline assets in Oklahoma have access to the major
natural gas producing areas 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
and the Permian Basin and transport natural gas to 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.
Our
transportation contracts for our regulated natural gas activities are based upon
rates stated in our tariffs. Tariffs specify the maximum rates
customers can be charged, which can be discounted to meet competition if
necessary, and the general terms and conditions for pipeline transportation
service, which are established at FERC or appropriate state jurisdictional
agency proceedings known as rate cases. In Texas and Kansas, natural
gas storage service is a fee business that may be regulated by the state in
which the facility operates and by the FERC for certain types of
services. In Oklahoma, natural gas gathering and natural gas storage
operations are also a fee business, but are not subject to rate regulation by
the OCC and have market-based rate authority from the FERC for certain types of
services.
Our
Natural Gas Pipelines segment’s revenues are typically derived from fee services
from the following types of contracts.
See Note
N of the Notes to Consolidated Financial Statements in this Annual Report for
additional discussion of unconsolidated affiliates.
Demand - Demand for pipeline
transportation service and natural gas storage is directly related 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. 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 - 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 basis 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 the United States 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 compete directly with other intrastate and interstate pipeline
companies and other storage facilities for natural gas. 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 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.
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 and have market-based
rate authority for certain types of services.
See
further discussion in the “Environmental and Safety Matters”
section.
Natural
Gas Liquids
Most natural gas produced at the wellhead contains a mixture of NGL
components such as ethane, propane, iso-butane, normal butane and natural
gasoline. Natural gas processing plants remove the NGLs from the
natural gas stream to realize the higher economic value of the NGLs and to meet
natural gas pipeline-quality specifications, which limit NGLs in the
natural
gas stream due to liquid and Btu content. 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, 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 exchange
services, optimization and marketing, pipeline transportation, isomerization and
storage, defined as follows:
See Note
N of the Notes to Consolidated Financial Statements in this Annual Report for
additional discussion of unconsolidated affiliates.
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 they
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. For the majority of 2009, ethane prices remained above
natural gas prices on a relative Btu basis, which resulted in ethane recovery
from processing plants that deliver NGLs to our natural gas liquids gathering
pipelines. We expect ethane prices in 2010 to remain above natural
gas prices on a relative Btu basis.
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
mix, propane, normal butane and natural gasoline are used by the petrochemical
industry to produce chemical products, such as plastic, rubber and synthetic
fiber.
Commodity
Prices - In recent years, crude oil, natural gas and NGL prices have been
volatile due to market conditions. We are exposed to market risk
associated with adverse changes in the price of NGLs, the basis 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 basis differential between the
Mid-Continent and Gulf Coast regions is narrow, optimization opportunities and
NGL shipments may decline, resulting in a decline in margin. 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 - Some NGL products
produced, gathered and distributed by our natural gas liquids facilities 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 when automotive travel is higher and during seasonal
periods when certain government restrictions on 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:
We are
responding to these industry conditions by making capital investments to access
new supplies, increase gathering and fractionation capacity, increase storage,
withdrawal and injection capabilities and reduce operating costs so that we may
effectively compete. We believe that we compete effectively with our
fractionation, pipelines and storage assets due to their strategic locations
connecting supply areas to market centers.
See
further discussion in the “Environmental and Safety Matters”
section.
ENVIRONMENTAL
AND SAFETY MATTERS
Additional
information about our environmental matters is included in Note K of the Notes
to Consolidated Financial Statements in this Annual Report.
The
United States Congress is actively considering legislation to reduce greenhouse
gas emissions, including carbon dioxide and methane. In addition,
other federal, state and regional initiatives to regulate greenhouse gas
emissions are under way. We are monitoring federal and state
legislation to assess the potential impact on our operations. We
estimate our direct greenhouse gas emissions annually as we collect all
applicable greenhouse gas emission data for the previous year. Our most recent estimate
indicates that our emissions are less than 4 million metric tons of carbon
dioxide equivalents on an annual basis. We expect to complete our
annual estimate for 2009 during the second quarter of 2010 and will post the
information on our Web site when available. We will continue efforts
to improve our ability to quantify our direct greenhouse gas emissions and will
report such emissions as required by the EPA’s Mandatory Greenhouse Gas
Reporting rule released in September 2009. The rule requires
greenhouse gas emissions reporting for affected facilities on an annual basis,
beginning with our 2010 emissions report that will be due in March 2011 and will
require us to track the emission equivalents for all NGLs delivered to our
customers. At this time, no legislation or other rules have been
enacted as to what costs, fees or expense will be associated with any of these
emissions. In addition, the EPA has issued a proposed rule on
air-quality standards, “National Emission Standards for Hazardous Air Pollutants
for Reciprocating Internal Combustion Engines,” also known as RICE NESHAP,
scheduled to be adopted in early 2013. The proposed rule will require
capital expenditures over the next three 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.
Pipeline Security> - Homeland
Security’s Transportation Security Administration, along with the United States
Department of Transportation, has completed a review and inspection of our
“critical facilities” and identified no material security issues.
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 new 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, (iv) following developing technologies to
capture carbon dioxide to keep it from reaching the atmosphere, and (v)
analyzing options for future energy investment.
We
participate in the EPA’s Natural Gas STAR Program to voluntarily reduce methane
emissions. We were honored in 2008 as the “Natural Gas STAR Gathering
and Processing Partner of the Year” for our efforts to positively address
environmental issues through voluntary implementation of emission-reduction
opportunities. In addition, 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. We expect to complete our
annual estimate for 2009 during the second quarter of 2010 and will post the
information on our Web site when available.
EMPLOYEES
We do not directly employ 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 our interstate
natural gas pipeline
assets
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, 2010, we utilized some or all
of the services of 1,273 people in addition to the other resources provided by
ONEOK and its affiliates.
INFORMATION
AVAILABLE ON OUR WEB SITE
We make
available on our Web site (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 Web site, and we will provide
copies of these documents upon request. Our Web site and any contents
thereof are not incorporated by reference into this report.
We also
make available on our Web site the Interactive Data Files voluntarily submitted
as Exhibit 101 to this Annual Report. In accordance with Rule 402 of
Regulation S-T, the Interactive Data Files shall not be deemed to be “filed” for
purposes of Section 18 of the Exchange Act, or otherwise subject to the
liability of that section, and shall not be incorporated by reference into any
registration statement or other document filed under the Securities Act or the
Exchange Act, except as shall be expressly set forth by specific reference in
such filing.
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 adversely affect our
business.
The
capital and credit markets have been experiencing volatility and
disruption. During the fourth quarter of 2008 and continuing into
2009, the volatility and disruption reached unprecedented levels. In
many cases, 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. If similar or more severe levels of market disruption and
volatility return, our access to capital and credit markets could be disrupted,
making growth through acquisitions and development projects difficult or
impractical to pursue until such time as markets stabilize.
Our
operating results may be materially adversely affected by unfavorable economic
and market conditions.
Economic
conditions worldwide have from time to time contributed to slowdowns in the oil
and 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.
Uncertainty
in the capital markets may increase the cost of debt and equity capital, which
may have a material adverse effect on our results of operations and
business.
In 2008 and continuing into 2009, economic conditions in the United
States experienced a downturn, primarily due to the sub-prime lending crisis,
volatile energy prices, inflation concerns, slower economic activity, decreased
consumer confidence, reduced corporate profits and capital spending, and
increased unemployment. These conditions had an adverse impact on the
credit markets. Although some of these conditions have improved in 2009
and 2010, continued uncertainty about market conditions may have an adverse
effect on us resulting from, but not limited to, difficulty in obtaining
financing
necessary
to expand facilities or acquire assets, increased financing cost and
increasingly restrictive covenants.
The
volatility of natural gas, crude oil and NGL prices could adversely affect our
cash flow.
A
significant portion of our revenues are derived from the sale of commodities
that are received as payment for gathering and processing services, for the
transportation and storage of natural gas, and for the sale of purity 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 the
following:
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 following 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 principally depends upon the
cash we generate from our operations. 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 non-cash 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 fully hedge 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:
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 fully hedge
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 have 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.
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 materially
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 risks that
adequate natural gas or NGL supplies will not be available 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
and legal 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:
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.
Additionally,
certain gas processing or other facilities (or parts thereof) used by us are
leased from third parties for specific periods. Our inability to
renew equipment leases or otherwise maintain the right to utilize such
facilities and equipment on acceptable terms, or the increased costs to maintain
such rights, could have a material adverse effect on our 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 and
transportation 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 facilities below expected levels of capacity and
efficiency. Other operational hazards and unforeseen interruptions include
adverse weather conditions, accidents, 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 explosions, fires, hurricanes, earthquakes, floods or other
similar events beyond our control. It is also possible that our
infrastructure 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 operation of
our pipeline 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 procure 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.
If
the level of drilling and production in the Mid-Continent, Rocky Mountain, Texas
and Gulf Coast regions substantially declines 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:
In
addition, drilling and production may be impacted by environmental regulations
governing water discharge. If the level of drilling and production in
any of these regions substantially declines, our volumes and revenue could be
materially reduced.
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 significantly decrease.
We depend
on natural gas supply from the Western Canada Sedimentary Basin for some of our
interstate pipelines, primarily our investment in Northern Border Pipeline, that
transports Canadian natural gas from the Western Canada Sedimentary Basin to the
Midwestern U.S. 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 materially adversely
impact our results of operations and cash flows available for
distributions.
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 located near high consequence
areas, where a leak or rupture could do the most harm. The rule also
requires operators to perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could
impact a high consequence area; improve data collection, integration and
analysis; repair and remediate the pipeline as necessary; and implement
preventive and mitigating actions. The results of these testing
programs could cause us to incur significant capital and operating expenditures
to make repairs or take remediation, preventive or mitigating actions that are
determined to be necessary.
Our
business is subject to increased regulatory oversight and potential
penalties.
The
natural gas industry historically has been heavily regulated; therefore, there
is no assurance that a more stringent regulatory approach will not be pursued by
the FERC and the United States Congress, especially in light of previous market
power abuse by certain companies engaged in interstate commerce. In
response to this issue, the United States Congress, in the Energy Policy Act of
2005 (EPACT), developed requirements intended to ensure that the energy market
is not impacted by the exercise of market power or manipulative
conduct. The FERC then adopted the Market Manipulation Rules to
implement the authority granted under EPACT. These rules are intended
to prohibit fraud and manipulation and are subject to broad
interpretation. EPACT also gave the FERC increased penalty authority
for violations.
Our
regulated pipelines’ transportation rates are subject to review and possible
adjustment by federal and state regulators.
Our
regulated pipelines are subject to extensive regulation by the FERC and state
regulatory agencies, which regulate most aspects of our pipeline business,
including our transportation rates. 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,
interstate transportation rates must be just and reasonable and not unduly
discriminatory.
Action by
the FERC or a state regulatory agency could adversely affect our pipeline
business’ ability to establish or charge rates that would cover future increases
in their costs, or even to continue to collect rates that cover current costs,
including a reasonable return. We cannot assure unitholders 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.
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:
Various
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, historical 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 non-compliance 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
significantly increase 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 K 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 materially adversely affected by increased
costs due to stricter pollution-control requirements or liabilities resulting
from non-compliance 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 materially
affect our profitability.
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.
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.
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 adequately assess 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.
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 would 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.
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 laborers 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
decreases our productivity and increases our costs. This shortage of
trained workers is the result of experienced workers reaching retirement age,
combined with the difficulty of attracting new laborers 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
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 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 climate change 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 are 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.
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, 5,900,000 common units and the
entire 2 percent general partner interest in us, which together constituted a
45.1 percent ownership interest in us as of December 31, 2009. 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. 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 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, adjourned to 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 vote
of the holders of at least 66-2/3 percent 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 directly employ 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:
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
owned 100 percent of our general partner interest and a 45.1 percent aggregate
equity interest in us as of December 31, 2009. 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 specifically stated 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. Six of the 10 members of the Board of Directors of our general
partner are either members of ONEOK’s Board of Directors or executive management
of ONEOK. Three independent members and one management member of the
Board of Directors of our general partner 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:
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.
Our
senior unsecured long-term debt has been assigned an investment-grade rating by
Moody’s of “Baa2” (Stable) and by S&P of “BBB” (Stable). 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 rating, particularly below investment grade, our borrowing costs would
increase, which would adversely affect our financial results, and our potential
pool of investors and funding sources could decrease. If Moody’s or
S&P were to downgrade our long-term ratings below investment grade, we
would, under certain circumstances, be required to offer to repurchase certain
of our senior notes. 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.
A
downgrade of our credit rating may require us to offer to repurchase certain of
our senior notes or may impair our ability to access capital.
We could
be required to offer to repurchase certain of our senior notes due 2010 and 2011
at par value, plus any accrued and unpaid interest, if Moody’s or S&P rate
those senior notes below investment grade (Baa3 for Moody’s and BBB- for
S&P) and the investment-grade rating is not reinstated within a period of 40
days; however, once the $250 million 2010 senior notes have been retired,
whether by maturity, redemption or otherwise, we will no longer have any
obligation to offer to repurchase the $225 million 2011 senior notes in the
event our credit rating falls below investment grade. Further, the
indenture governing our senior notes due 2010 and 2011 includes an event of
default upon acceleration of other indebtedness of $25 million or more, and the
indenture governing our senior notes due 2012, 2016, 2019, 2036 and 2037
includes an event of default upon the acceleration of other indebtedness of $100
million or more that would be triggered by such an offer to
repurchase. Such an event of default would entitle the trustee or the
holders of 25 percent in aggregate principal amount of the outstanding senior
notes due 2010, 2011, 2012, 2016, 2019, 2036 and 2037 to declare those 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
other obligations.
As of
December 31, 2009, we had total indebtedness of approximately $3.6
billion. Our indebtedness could have significant
consequences. For example, it could:
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 adversely affect our ability to repay our 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. Please refer to the “Liquidity and Capital Resources” section
of Management’s Discussion and Analysis of Financial Condition and Results of
Operation. 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 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 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:
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 may also 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 were subsequently 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 expressly made 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 clearly established in some of the states in which we
do business.
TAX
RISKS
Our
tax treatment depends on our status as a partnership for federal income tax
purposes. Additionally, other than our corporate subsidiaries, we are
subject to entity-level taxation in certain states. If the IRS were
to treat us as a corporation 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 substantially
reduced.
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.
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 we likely would pay state taxes as
well. 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 substantially reduced. Therefore, treatment of
us as a corporation would result in a material reduction in the after-tax return
to our common unitholders, likely causing a substantial reduction in the value
of our common units.
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 or other forms of taxation. For
example, beginning in 2008, we were required to pay the revised Texas franchise
tax at a maximum effective rate of 0.7 percent of our gross revenue that is
apportioned to Texas. Imposition of such tax on us by Texas, or any
other state, reduces the cash available for distribution to our common
unitholders.
The
tax treatment of our structure could be subject to potential legislative,
judicial or administrative changes and differing interpretations, possibly on a
retroactive basis.
The
federal income tax treatment of us and common unitholders depends in some
instances on determinations of fact and interpretations of complex provisions of
federal income tax law. The federal income tax rules are constantly
under review by persons involved in the legislative process, the IRS and the
United States Treasury Department (Treasury), frequently resulting in revised
interpretations of established concepts, statutory changes, revisions to
Treasury regulations and other modifications and interpretations. The IRS pays
close attention to the proper application of tax laws to
partnerships. The present federal income tax treatment of us and/or
an investment in our common units may be modified by administrative, legislative
or judicial interpretation at any time. For example, in response to
certain recent developments, members of the
United
States Congress are considering substantive changes to the definition of
qualifying income under the Internal Revenue Code Section 7704(d) and the
treatment of certain types of income earned from profits interests in the
partnerships. Any modification to the federal income tax laws and
interpretations thereof may or may not be applied retroactively and could make
it more difficult or impossible for us to meet the exception to be treated for
federal income tax purposes as a partnership that is not taxable as a
corporation (referred to as the “Qualifying Income Exception”), affect or cause
us to change our business activities, affect the tax consequences for common
unitholders of an investment in us, change the character or treatment of
portions of our income and adversely affect an investment in our common
units. We are unable to predict whether any of these or other changes
or proposals will ultimately be enacted. Any such changes could
negatively impact 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 contest will be borne by our
unitholders and general partner.
We have
not requested any ruling from the IRS with respect to our treatment as a
partnership for federal income tax purposes or any other matter affecting
us. The IRS may adopt positions that differ from the federal income
tax positions we take. 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 adversely impact 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 materially and
adversely impact 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
result in a reduction in cash available to pay distributions to our unitholders
and our general partner and thus will be borne indirectly by our unitholders and
our general partner.
A
unitholder will be required to pay taxes on the unitholder’s share of our
taxable income even if the unitholder does not receive any cash distributions
from us.
A
unitholder will be required to pay federal income taxes and, in some cases,
state and local income taxes on the unitholder’s share of our taxable income,
whether or not the unitholder receives 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 the unitholder’s share of our taxable income.
Unitholders
may have negative tax consequences if we default on our debt or sell
assets.
If we
default on any of our debt, the lenders will have the right to sue us for
non-payment. Such an action could cause negative tax consequences for
unitholders through the realization of taxable income by unitholders without a
corresponding cash distribution. Likewise, if we were to dispose of
assets and realize a taxable gain while there is substantial debt outstanding
and proceeds of the sale were applied to the debt, unitholders could have
increased taxable income without a corresponding cash distribution.
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 on the sale of common units equal to
the difference between the amount realized and the unitholder’s tax basis in
those common units. A unitholder’s amount realized will be measured
by the sum of the cash and the fair market value of other property received plus
the unitholder’s share of our nonrecourse liabilities. Because the
amount realized includes a unitholder’s share of our nonrecourse liabilities,
the gain recognized on the sale of common units could result in a tax liability
in excess of any cash received from the sale. Prior distributions to
a unitholder in excess of the total net taxable income allocated to a unitholder
for a common unit, which decreased the tax basis in that common unit, will, in
effect, become taxable income to a unitholder if the common unit is sold at a
price greater than the tax basis in that common unit, even if the price received
is less than the original cost. A substantial portion of the amount
realized, whether or not representing a gain, may be ordinary income to a
unitholder. Should the IRS successfully contest some positions we
take, unitholders could recognize more gain on the sale of units than would be
the case under those positions, without the benefit of decreased income in prior
years.
Tax-exempt
entities and non-U.S. 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 individual retirement accounts
and non-U.S. persons, raises issues unique to them. For example,
virtually all of our income allocated to unitholders who are organizations
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-U.S. persons may be subject to U.S.
withholding taxes. Non-U.S. persons will be required to file U.S.
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 adversely affect 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
applicable Treasury regulations. A successful IRS challenge to those
positions could adversely affect 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 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 this 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
will 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 will be subject to other taxes,
such as state and local income taxes, unincorporated business taxes and estate,
inheritance or intangible taxes that are imposed by the various jurisdictions in
which we do business or own property. Unitholders will 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. We may own property or
conduct business in other states or foreign countries in the
future.
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 adversely affect 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 non-resident 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 the total interest in our capital and
profits within a 12-month period will result in the termination of our
Partnership for federal income tax purposes.
We will
be considered to have terminated 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. Our termination would, among other
things, result in the closing of our taxable year for all unitholders, which may
result in us filing two tax returns for one fiscal year.
Our
termination could also result in a deferral of depreciation deductions allowable
in computing taxable income. Our termination currently would not
affect our classification as a partnership for federal income tax purposes,
instead, we would be treated as a new partnership, we must make new tax
elections, and we could be subject to penalties if we were unable to determine
that the termination had occurred.
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
adversely affect 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 adversely affect
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 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 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
Natural
Gas Pipelines
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,
following natural gas explosions and eruptions of natural gas geysers. We
began injecting brine into the 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 2011. Monitoring of the
facility and review of the data for the geoengineering 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.
Natural
Gas Liquids
In
addition, we lease four NGL storage facilities in Oklahoma, Kansas and Texas
with operating storage capacity of approximately 3.2 MMBbl. We also
own and lease assets through an affiliate at the Bushton facility in Kansas,
which includes 150 MBbl/d of fractionation capacity.
During
2008, we added new natural gas liquids fractionation facilities at the Bushton
location, in conjunction with other changes that were made to the NGL
fractionation capabilities of the existing plant. We currently have
150 MBbl/d of active NGL fractionation capacity as a result of combining the
previously existing fractionation equipment with the new fractionation
facilities. We resumed fractionating NGLs at the facilities in the
second half of 2008.
We
calculate utilization rates using a weighted-average approach, adjusting for the
in-service dates of assets placed in service during 2009 and
2008. The utilization rates of our non-FERC-regulated NGL pipelines
and FERC-regulated NGL gathering pipelines reflect the Arbuckle Pipeline placed
in service in August 2009.
Our
fractionation utilization rate reflects approximate proportional capacity
associated with ownership interests noted above and for our Bushton facility,
which was placed in service during the second half of 2008.
ITEM
3. LEGAL
PROCEEDINGS
ITEM
4. SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not
applicable.
PART II
ITEM
5. MARKET
FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES
OF EQUITY SECURITIES
MARKET
INFORMATION AND HOLDERS
Our
equity consists of a 2 percent general partner interest and a 98 percent limited
partner interest. Our limited partner interests are represented by
our common units, which are listed on the NYSE under the trading symbol “OKS,”
and our Class B limited partner units. The following table sets forth
the high and low closing prices of our common units for the periods
indicated:
At
February 12, 2010, there were 761 holders of record of our 65,162,777
outstanding common units. ONEOK and its affiliates own all of the
Class B units, 5,900,000 common units and the entire 2 percent general partner
interest in us, which together constituted a 42.8 percent ownership interest in
us upon completion of our February 2010 public offering of common
units.
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:
In
January 2010, our general partner declared a cash distribution of $1.10 per unit
($4.40 per unit on an annualized basis) for the fourth quarter of 2009, which
was paid on February 12, 2010, to unitholders of record as of January 29,
2010.
CASH
DISTRIBUTION POLICY
Under our
Partnership Agreement, we make distributions to our partners with respect to
each calendar quarter in an amount equal to 100 percent of available cash 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:
We paid
cash distributions to our general and limited partners of $500.3 million for
2009 and $453.0 million for 2008, which included an incentive distribution to
our general partner of $84.7 million for 2009 and $69.9 million for
2008. 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, 2004, and ending on December 31, 2009. 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.
ITEM
6. SELECTED
FINANCIAL DATA
The
following table sets forth our selected financial data for the periods
indicated:
ITEM
7. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
The
following discussion and analysis should be read in conjunction with our audited
consolidated financial statements and the Notes to Consolidated Financial
Statements in this Annual Report.
EXECUTIVE
SUMMARY
The
following discussion highlights some of our achievements and significant issues
affecting us during the past year. Please refer to the “Capital
Projects,” “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.
We intend
to pursue growth in our natural gas businesses through well connections and
contract renegotiations and through new plant construction, expansions and
extensions of our existing systems and plants. For our natural gas liquids
business, we intend to continue to focus on adding new supply connections and
expanding our existing assets. We plan to spend approximately $362 million
on capital expenditures in 2010, of which approximately $278 million will be for
growth projects. We may also pursue strategic acquisitions related to
gathering, processing, fractionating, storing, transporting or marketing natural
gas and NGLs.
Equity Issuances> - In July
2009, we completed an underwritten public offering of 5,486,690 common units,
including the partial exercise by the underwriters of their over-allotment
option, at $45.81 per common unit, generating net proceeds of approximately
$241.6 million. In conjunction with the offering, ONEOK Partners GP
contributed an aggregate of $5.1 million in order to maintain its 2 percent
general partner interest in us. We used the proceeds from the sale of
common units
and the
general partner contributions to repay borrowings under our Partnership Credit
Agreement and for general partnership purposes. As a result of these
transactions, ONEOK and its subsidiaries held an aggregate 45.1 percent interest
in us at December 31, 2009.
In
February 2010, we completed an underwritten public offering of 5,500,900 common
units, including the partial exercise by the underwriters of their
over-allotment option, at $60.75 per common unit, generating net proceeds of
approximately $322.6 million. In conjunction with the offering, ONEOK
Partners GP contributed $6.8 million in order to maintain its 2 percent general
partner interest in us. We used the proceeds from the sale of common units
and the general partner contribution to repay borrowings under our Partnership
Credit Agreement and for general partnership purposes. As a result of
these transactions, ONEOK and its subsidiaries own a 42.8 percent aggregate
equity interest in us.
SIGNIFICANT
ACQUISITIONS AND DIVESTITURES
settlement
was finalized in April 2008, with no material adjustments. These
assets are included in our Natural Gas Liquids segment.
CAPITAL
PROJECTS
As part
of a long-term agreement, Williams dedicated its NGL production from two of its
natural gas processing plants in Wyoming, capable of delivering over 70 MBbl/d
to the Overland Pass Pipeline. We provide downstream fractionation,
storage and transportation services to Williams. We have also reached
agreements with certain producers for supply commitments to the D-J Basin and
Piceance Lateral pipelines. We have NGL production dedicated from new
and existing plants that we expect to provide throughput of more than 200 MBbl/d
to the Overland Pass Pipeline over the next three to five years.
We also
invested approximately $239 million, excluding AFUDC, to expand our existing
fractionation and storage capabilities and to increase the capacity of our
natural gas liquids distribution pipelines. Part of this expansion
included adding new fractionation facilities at our Bushton, Kansas, location,
which increased the total fractionation capacity at the Bushton facility to 150
MBbl/d from 80 MBbl/d. The addition of the new facilities and the
upgrade to the existing fractionator were completed in October
2008. Additionally, portions of our natural gas liquids distribution
pipeline upgrades were completed in the second and third quarters of
2008. Overland Pass Pipeline Company and the associated expansions
are included in our Natural Gas Liquids segment.
The
demand for surface easements increased dramatically in Texas and Oklahoma over
the last two years because of increased oil and natural gas exploration and
production activities, as well as pipeline construction. As
previously reported, project costs have been more expensive than originally
estimated due to delays associated with right-of-way acquisition, increased
materials costs and difficult construction conditions associated with several
weeks of heavy spring rains in 2009, resulting in greatly reduced construction
productivity. We also experienced increased costs due to a number of
scope
changes,
arising primarily from additional supply development
opportunities. We estimate project costs will be approximately $490
million, excluding AFUDC, for the current capacity.
IMPACT
OF NEW ACCOUNTING STANDARDS
Information
about the impact of new accounting standards is included in Note A of the Notes
to Consolidated Financial Statements in this Annual Report:
The above
accounting standards did not or are not expected to have a material impact on
our consolidated financial statements, results of operations or cash
flows.
CRITICAL
ACCOUNTING POLICIES AND ESTIMATES
The
preparation of our consolidated financial statements and related disclosures in
accordance with GAAP requires us to make estimates and assumptions with respect
to values or conditions that cannot be known with certainty that affect the
reported amount of assets and liabilities, and the disclosure of contingent
assets and liabilities at the date of the consolidated financial
statements. These estimates and assumptions also affect the reported
amounts of revenue and expenses during the reporting period. Although
we believe these estimates and assumptions are reasonable, actual results could
differ from our estimates.
The
following is a summary of our most critical accounting estimates, which are
defined as those policies most important to the portrayal of our financial
condition and results of operations and requiring our management’s most
difficult, subjective or complex judgment, particularly because of the need to
make estimates concerning the impact of inherently uncertain
matters. We have discussed the development and selection of our
critical accounting policies and estimates with the Audit Committee of our Board
of Directors.
Impairment of Goodwill, Long-Lived
Assets and Intangible Assets> - We assess our goodwill
for impairment at least annually. There were no impairment charges
resulting from our July 1, 2009, 2008 or 2007 impairment tests.
As part
of our impairment test, an initial assessment is made by comparing the fair
value of a reporting unit with its book value, including goodwill. To
estimate the fair value of our reporting units, we use two generally accepted
valuation approaches, an income approach and a market approach. Under
the income approach, we use anticipated cash flows over a period of years plus a
terminal value and discount these amounts to their present value using
appropriate rates of return that are consistent with a market participant’s
perspective. Under the market approach, we apply multiples to
forecasted cash flows. The multiples used are consistent with a
market participant’s perspective of historical asset transactions The
forecasted cash flows are consistent with a market participant’s perspective of
average forecasted cash flows for a reporting unit over a period of
years.
Our
estimates of fair value significantly exceeded the book value of our reporting
units in our July 1, 2009, impairment test. Even if the estimated
fair values used in our July 1, 2009, impairment test were reduced by 10
percent, no impairment charges would have resulted. The following
table sets forth our goodwill, by segment, at both December 31, 2009 and
2008:
See Notes
A and F of the Notes to Consolidated Financial Statements in this Annual Report
for additional discussion of goodwill and related disclosures.
We assess
our long-lived assets, including intangible assets with a finite useful life,
for impairment whenever events or changes in circumstances indicate that its
carrying amount may exceed its fair value. In step one of the
impairment test, the carrying amount of a long-lived asset is not recoverable if
it exceeds the sum of the undiscounted future cash flows expected to result from
the use and eventual disposition of the asset. If the carrying amount
is not recoverable, we record an impairment loss equal to the difference between
the carrying value and the fair value of the long-lived asset. This
type of analysis requires us to make assumptions and estimates regarding
industry economic factors and the profitability of future business
strategies. We determined that there were no asset impairments in
2009, 2008 or 2007.
We had
$272.2 million and $279.8 million of intangible assets recorded on our
Consolidated Balance Sheets as of December 31, 2009 and 2008, respectively, all
of which was recorded in our Natural Gas Liquids segment.
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. Therefore, we periodically re-evaluate the amount at which we
carry our equity method investments to determine whether current events or
circumstances warrant adjustments to our carrying value. We
determined that there were no impairments to our investments in unconsolidated
affiliates in 2009, 2008 or 2007.
Our
impairment tests require the use of assumptions and estimates. If
actual results are not consistent with our assumptions and estimates or our
assumptions and estimates change due to new information, we may be exposed to an
impairment charge.
See Notes
C and D of the Notes to Consolidated Financial Statements in this Annual Report
for additional discussion of fair value measurements and derivatives and risk
management activities.
FINANCIAL
RESULTS AND OPERATING INFORMATION
Consolidated
Operations
Selected Financial Results> -
The following table sets forth certain selected financial results for the
periods indicated:
2009 vs. 2008 - Net margin
decreased due primarily to the following:
Operating
costs increased due primarily to higher employee-related costs, incremental
costs associated with the operation of the Overland Pass Pipeline, the Arbuckle
Pipeline and the expanded Bushton Plant fractionator, outside services expenses
and general taxes related to our completed capital projects.
Depreciation
and amortization increased due primarily to our completed capital projects,
which are discussed beginning on page 37.
Equity
earnings from investments decreased due primarily to lower subscription volumes
and rates on Northern Border Pipeline. Additionally, there was a gain
on the sale of Bison Pipeline LLC by Northern Border Pipeline in
2008. Equity earnings from investments also decreased due to lower
volumes gathered in our Natural Gas Gathering and Processing segment’s equity
investments, whose assets are primarily located in the Powder River Basin of
Wyoming.
Allowance
for equity funds used during construction decreased due primarily to the
completion of the Arbuckle Pipeline, the Overland Pass Pipeline and related
expansion projects, and the Guardian Pipeline expansion and
extension.
Interest
expense increased due primarily to our March 2009 debt issuance and a decrease
in capitalized interest due to the completion of our capital
projects.
Capital
expenditures decreased due primarily to the completion of our capital
projects.
2008 vs. 2007 - Net margin
increased due primarily to the following:
Operating
costs increased due primarily to incremental operating expenses associated with
the assets acquired from Kinder Morgan, increased outside services primarily
associated with scheduled maintenance activities at our Medford and Mont Belvieu
fractionators, and chemical costs. Operating costs also increased due
to costs associated with the startup of our newly expanded Bushton fractionator
and Overland Pass Pipeline.
Depreciation
and amortization increased due primarily to our completed capital projects and
the assets acquired from Kinder Morgan.
Equity
earnings from investments increased due primarily to higher gathering revenues
in our various investments as well as a gain on the sale of Bison Pipeline LLC
by Northern Border Pipeline in 2008, offset partially by reduced throughput on
Northern Border Pipeline. We own a 50 percent equity interest in
Northern Border Pipeline.
Allowance
for equity funds used during construction and capital expenditures increased due
to increased spending for our capital projects, which are discussed beginning on
page 37.
Interest
expense increased due primarily to increased borrowings to fund our capital
projects.
More
information regarding our results of operations is provided in the following
discussion of operating results for each of our segments.
Natural
Gas Gathering and Processing
Selected Financial Results >-
The following table sets forth certain selected financial results for our
Natural Gas Gathering and Processing segment for the periods
indicated:
2009 vs. 2008 - Net margin
decreased primarily as a result of the following:
Operating
costs decreased primarily as a result of lower costs for chemicals and
maintenance activities. These decreases were offset partially by
higher employee-related costs.
Depreciation
and amortization increased primarily as a result of our completed capital
projects.
Gain on
sale of assets increased due to the sale of excess compression
equipment.
Equity
earnings from investments decreased primarily as a result of decreased earnings
from lower volumes gathered in our equity investments, which are primarily
located in the Powder River Basin of Wyoming.
Capital
expenditures decreased due primarily to the completion of a pipeline expansion
project into the Woodford Shale in September of 2008 in Oklahoma and the
Williston Basin gas processing plant expansion.
2008 vs. 2007 - Net margin
increased due primarily to the following:
Operating
costs increased due primarily to increased costs for chemicals and maintenance
parts, and a favorable legal settlement received in June 2007, which reduced
legal costs for 2007. These increases were offset partially by
decreased equipment lease costs in 2008 associated with the Bushton
Plant.
Depreciation
and amortization increased primarily as a result of our completed capital
projects.
Equity
earnings from investments increased due primarily to higher gathering revenues
in our Fort Union Gas Gathering investment as a result of capacity
expansions.
Capital
expenditures increased due to our increased growth activities, primarily in the
Rocky Mountain region.
Selected Operating Information>
- The following tables set forth selected operating information for our Natural
Gas Gathering and Processing segment for the periods indicated:
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