form_10-k.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-K
X ANNUAL REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE
ACT OF 1934
For the
fiscal year ended December 31, 2008.
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 001-13643
ONEOK,
Inc.
(Exact
name of registrant as specified in its charter)
Oklahoma
|
73-1520922
|
(State
or other jurisdiction of
incorporation
or organization)
|
(I.R.S.
Employer Identification No.)
|
|
|
100
West Fifth Street, Tulsa, OK
|
74103
|
(Address
of principal executive offices)
|
(Zip
Code)
|
Registrant’s
telephone number, including area code (918) 588-7000
Securities
registered pursuant to Section 12(b) of the Act:
Common
stock, par value of $0.01
|
New
York Stock Exchange
|
(Title
of Each Class)
|
(Name
of Each Exchange on which
Registered)
|
Securities
registered pursuant to Section 12(g) of the Act: None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes X No__.
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes __ No X.
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports) and (2) has been subject to such filing requirements for
the past 90 days. Yes X No
__
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Registration S-K (§229.405) 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 checkmark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of “accelerated
filer and large accelerated filer” in Rule 12b-2 of the Exchange
Act. (Check one)
Large
accelerated filer X Accelerated
filer
__ Non-accelerated
filer __
Indicate
by checkmark whether the registrant is a shell company (as defined in Rule 12b-2
of the Act). Yes__ No X.
Aggregate
market value of registrant’s common stock held by non-affiliates based on the
closing trade price on June 30, 2008, was $5.1 billion.
On
February 18, 2009, the Company had 105,239,496 shares of common stock
outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE:
Portions
of the definitive proxy statement to be delivered to shareholders in connection
with the Annual Meeting of Shareholders to be held May 21, 2009, are
incorporated by reference in Part III.
2008
ANNUAL REPORT ON FORM 10-K
Part
I.
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Page
No.
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Item
1.
Item
1A.
Item
1B.
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5-17
17-29
29
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Item
2.
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29-30
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Item
3.
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31-32
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Item
4.
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32
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Part
II.
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|
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Item
5.
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32-34
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Item
6.
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35
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Item
7.
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35-62
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Item
7A.
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63-66
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Item
8.
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67-117
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Item
9.
Item
9A.
Item
9B.
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117
117-118
118
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Part
III.
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|
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Item
10.
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118-119
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Item
11.
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119
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Item
12.
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119
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Item
13.
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120
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Item
14.
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120
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Part
IV.
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|
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Item
15.
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120-125
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126
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As used
in this Annual Report on Form 10-K, references to “we,” “our” or “us” refers to
ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries,
unless the context indicates otherwise.
GLOSSARY
The
abbreviations, acronyms and industry terminology used in this Annual Report on
Form 10-K are defined as follows:
|
AFUDC
|
Allowance
for funds used during construction
|
|
APB
Opinion
|
Accounting
Principles Board Opinion
|
|
ARB
|
Accounting
Research Bulletin
|
|
Bbl
|
Barrels,
1 barrel is equivalent to 42 United States
gallons
|
|
BBtu/d
|
Billion
British thermal units per day
|
|
Bcf/d
|
Billion
cubic feet per day
|
|
Black
Mesa Pipeline
|
Black
Mesa Pipeline, Inc.
|
|
Btu
|
British
thermal units, a measure of the amount of heat required to raise
the
temperature of one pound of water one degree
Fahrenheit
|
|
Bushton
Plant
|
Bushton
Gas Processing Plant
|
|
EBITDA
|
Earnings
before interest, taxes, depreciation and
amortization
|
|
EITF
|
Emerging
Issues Task Force
|
|
EPA
|
United
States Environmental Protection
Agency
|
|
Exchange
Act
|
Securities
Exchange Act of 1934, as amended
|
|
FASB
|
Financial
Accounting Standards Board
|
|
FERC
|
Federal
Energy Regulatory Commission
|
|
Fort
Union Gas Gathering
|
Fort
Union Gas Gathering, L.L.C.
|
|
GAAP
|
Generally
Accepted Accounting Principles in the United
States
|
|
Guardian
Pipeline
|
Guardian
Pipeline, L.L.C.
|
|
Heartland
|
Heartland
Pipeline Company
|
|
IRS
|
Internal
Revenue Service
|
|
KCC
|
Kansas
Corporation Commission
|
|
KDHE
|
Kansas
Department of Health and
Environment
|
|
LDCs
|
Local
Distribution Companies
|
|
LIBOR
|
London
Interbank Offered Rate
|
|
MBbl/d
|
Thousand
barrels per day
|
|
Midwestern
Gas Transmission
|
Midwestern
Gas Transmission Company
|
|
MMBtu
|
Million
British thermal units
|
|
MMBtu/d
|
Million
British thermal units per day
|
|
MMcf/d
|
Million
cubic feet per day
|
|
Moody’s
|
Moody’s
Investors Service, Inc.
|
|
NGL(s)
|
Natural
gas liquid(s)
|
|
Northern
Border Pipeline
|
Northern
Border Pipeline Company
|
|
NYMEX
|
New
York Mercantile Exchange
|
|
NYSE
|
New
York Stock Exchange
|
|
OBPI
|
ONEOK
Bushton Processing Inc.
|
|
OCC
|
Oklahoma
Corporation Commission
|
|
ONEOK
Leasing Company
|
ONEOK
Leasing Company, L.L.C.
|
|
ONEOK
Partners
|
ONEOK
Partners, L.P.
|
|
ONEOK
Partners GP
|
ONEOK
Partners GP, L.L.C., a wholly owned subsidiary of ONEOK
and the
sole general partner of ONEOK
Partners
|
|
OPIS
|
Oil
Price Information Service
|
|
Overland
Pass Pipeline Company
|
Overland
Pass Pipeline Company LLC
|
|
RRC
|
Texas
Railroad Commission
|
|
S&P
|
Standard
& Poor’s Rating Group
|
|
SEC
|
Securities
and Exchange Commission
|
|
Statement
|
Statement
of Financial Accounting
Standards
|
|
TC
PipeLines
|
TC
PipeLines Intermediate Limited Partnership, a subsidiary of TC
PipeLines,
LP
|
|
TransCanada
|
TransCanada
Corporation
|
The
statements in this Annual Report on Form 10-K 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,” “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 and 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 on Form 10-K for the year ended December 31, 2008.
PART
I
GENERAL
We are a
diversified energy company and successor to the company founded in 1906 known as
Oklahoma Natural Gas Company. Our common stock is listed on the NYSE
under the trading symbol “OKE.” We are the sole general partner and
own 47.7 percent of ONEOK Partners, L.P. (NYSE: OKS), one of the largest
publicly traded master limited partnerships. ONEOK Partners is a
leader in the gathering, processing, storage and transportation of natural gas
in the United States. In addition, ONEOK Partners owns 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
are the largest natural gas distributor in Oklahoma and Kansas and the third
largest natural gas distributor in Texas, providing service as a regulated
public utility to wholesale and retail customers. Our largest
distribution markets are Oklahoma City and Tulsa, Oklahoma; Kansas City,
Wichita, and Topeka, Kansas; and Austin and El Paso, Texas. Our
energy services operation is engaged in providing premium natural gas marketing
services to wholesale and retail customers across the United States and
Canada.
DESCRIPTION
OF BUSINESS SEGMENTS
We report
operations in the following reportable business segments:
For
financial and statistical information regarding our business segments, see below
in the “Segment Financial Information” section, Item 7, Management’s Discussion
and Analysis of Financial Condition and Results of Operation and Note M of the
Notes to Consolidated Financial Statements in this Annual Report on Form
10-K.
Business
Strategy
Our
primary business strategy is to deliver consistent growth and sustainable
earnings, while focusing on safe, reliable, environmentally sound and legally
compliant operations for our customers, employees, contractors and the public
through the following:
·
|
developing
and executing internally generated growth projects within our ONEOK
Partners segment;
|
·
|
increasing
the level of sustainable earnings in our Distribution
segment;
|
·
|
continuing
our focus on physical activities in our Energy Services
segment;
|
·
|
executing
strategic acquisitions that utilize our core competencies;
and
|
·
|
managing
our balance sheet over the long term to maintain our credit ratings at or
above their current investment-grade
levels.
|
ONEOK Partners - ONEOK
Partners’ primary business objectives are to generate cash flow sufficient to
pay quarterly cash distributions to its unitholders and to increase its
quarterly cash distributions over time. ONEOK Partners’ ability to
maintain and grow its distributions to unitholders depends on, among other
things, the growth of its existing businesses and strategic
acquisitions. We plan to continue pursuing internal growth
opportunities and strategic acquisitions related to gathering, processing,
fractionating, transporting, storing and marketing natural gas and NGLs that
will utilize our core competencies, minimize commodity price risk and provide
long-term, sustainable and stable cash flows. Our strategy focuses on
maintaining stable cash flows through predominantly fee-based income, equity
earnings derived primarily from fee-based earnings, and by managing commodity
and spread risk.
Distribution - Our integrated
strategy for our LDCs incorporates a rates and regulatory plan that includes
positive relationships with regulators, consistent strategies and synchronized
rate case filings. We focus on growth of our customer count and rate
base through efficient investment in our system while emphasizing safety and
cost control. We provide customer choice programs designed to reduce
volumetric sensitivity and create value for our customers.
Energy Services - Our Energy
Services segment creates value by providing premium services to our customers by
delivering physical and risk management products and services to our customers
through our network of contracted gas supply and leased transportation and
storage assets. We optimize our storage and transportation capacity
through the daily application of market knowledge and effective risk
management.
Outlook
for 2009
We expect
continued deteriorating economic conditions in 2009, with downward pressures,
relative to 2008, on commodity prices for natural gas, NGLs and crude oil.
We anticipate that lower commodity prices will result in reduced drilling
activity and economic conditions will result in reduced petrochemical
demand. We also expect continued volatility and disruption in the
financial markets which could result in an increased cost of
capital. We expect depressed commodity prices and tighter capital
markets to also result in the sale or consolidation of underperforming assets in
the industry, which may present opportunities for us.
ONEOK Partners - ONEOK
Partners intends to pursue continued growth in its natural gas businesses
through well-connects, contract renegotiations and expansions and extensions of
its existing systems and plants. For its natural gas liquids businesses,
ONEOK Partners will continue to focus on adding new supply connections and
optimizing existing assets, as well as completing the growth projects currently
under construction. Capital expenditures in 2009 are expected to be
significantly lower than in 2008 when ONEOK Partners spent approximately $1.3
billion. ONEOK Partners plans to spend approximately $425 million on
capital expenditures in 2009, of which approximately $355 million is for growth
projects. ONEOK Partners also plans to pursue strategic acquisitions
related to gathering, processing, fractionating, storing, transporting and
marketing natural gas and NGLs.
Distribution - In our
Distribution segment, we plan to grow our asset base through efficient capital
investment in infrastructure and technology and increase the level of
sustainable earnings.
Energy Services - In our
Energy Services segment, we expect higher natural gas basis
differentials. We plan to manage our current portfolio of supply and
leased assets, reduce storage capacity utilization as compared with 2008,
continue to offer premium products and services, and draw on the competitive
position of our assets to extract incremental value through daily optimization
of storage and transportation assets. Additionally, we plan to grow
our asset management agreements with LDCs, use hedging to establish base margins
and capture incremental margins related to location and seasonal differences,
and continue to achieve high customer satisfaction.
SIGNIFICANT
DEVELOPMENTS IN 2008
Capital Projects - ONEOK
Partners placed the following projects in-service during 2008:
·
|
January
- Midwestern Gas Transmission’s eastern extension
pipeline;
|
·
|
July
- final phase of Fort Union Gas Gathering expansion
project;
|
·
|
September
- Woodford Shale natural gas liquids pipeline
extension;
|
·
|
October
- Bushton Fractionation expansion;
|
·
|
November
- Overland Pass Pipeline from Opal, Wyoming to Conway, Kansas;
and
|
·
|
December
- partial operations of the Guardian Pipeline extension with interruptible
service from Ixonia, Wisconsin, to Green Bay,
Wisconsin.
|
Equity Issuance - In March
2008, we purchased from ONEOK Partners, in a private placement, an additional
5.4 million of ONEOK Partners’ common units for a total purchase price of
approximately $303.2 million. In addition, ONEOK Partners completed a
public offering of 2.5 million common units at $58.10 per common unit and
received net proceeds of $140.4 million after deducting underwriting discounts
but before offering expenses. In conjunction with ONEOK Partners’
private placement and public offering of common units, ONEOK Partners GP
contributed $9.4 million to ONEOK Partners in order to maintain its 2 percent
general partner interest.
In April
2008, ONEOK Partners sold an additional 128,873 common units at $58.10 per
common unit to the underwriters of the public offering upon the partial exercise
of their option to purchase additional common units to cover
over-allotments. ONEOK Partners received net proceeds of
approximately $7.2 million from the sale of these common units after deducting
underwriting discounts but before offering expenses. In conjunction
with the partial exercise by the underwriters, ONEOK Partners GP contributed
$0.2 million to ONEOK Partners in order to maintain its 2 percent general
partner interest. Following these transactions, our ownership
interest in ONEOK Partners is 47.7 percent.
SEGMENT
FINANCIAL INFORMATION
Operating Income - The
following table sets forth operating income by segment, as a percentage of our
consolidated total, excluding any gain or (loss) on sale of assets, for the
periods indicated.
|
Years
Ended December 31,
|
Operating
Income
|
2008
|
2007
|
2006
|
ONEOK
Partners
|
70%
|
|
|
54%
|
|
|
53%
|
|
|
Distribution
|
21%
|
|
|
21%
|
|
|
16%
|
|
|
Energy
Services
|
8%
|
|
|
25%
|
|
|
31%
|
|
|
Other
and Eliminations
|
1%
|
|
|
*
|
|
|
*
|
|
|
Total
|
100%
|
|
|
100%
|
|
|
100%
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Represents a value of less than 1 percent.
|
|
|
|
|
|
|
|
|
Customers and Total Assets -
See Note M of the Notes to Consolidated Financial Statements in this Annual
Report on Form 10-K for discussion of revenues from external customers under
“Customers” and disclosure of total assets by segment within the “Operating
Segment Information” table.
Intersegment Revenues - The
following table sets forth the percentage of intersegment revenues to total
revenue, by segment, for the periods indicated.
|
Years
Ended December 31,
|
Intersegment
Revenues
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
ONEOK
Partners
|
10%
|
|
|
11%
|
|
|
13%
|
|
|
Distribution
|
*
|
|
|
*
|
|
|
*
|
|
|
Energy
Services
|
8%
|
|
|
7%
|
|
|
8%
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Represents a value of less than 1 percent.
|
|
|
|
|
|
|
|
|
See Note
M of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K for additional information about intersegment revenues.
NARRATIVE
DESCRIPTION OF BUSINESS
ONEOK
Partners
Ownership - We own
approximately 42.4 million common and Class B limited partner units, and the
entire 2 percent general partner interest, which, together, represents a 47.7
percent ownership interest in ONEOK Partners. We receive
distributions from ONEOK Partners on our common and Class B units and our 2
percent general partner interest. See Note Q of the Notes to
Consolidated Financial Statements in this Annual Report on Form 10-K for
discussion of our incentive distribution rights.
Business Strategy - ONEOK
Partners’ primary business objectives are to generate cash flow sufficient to
pay quarterly cash distributions to its unitholders and to increase its
quarterly cash distributions over time. ONEOK Partners plans to
accomplish these objectives while focusing on safe, environmentally sound and
legally compliant operations for its customers, employees, contractors and the
public through the following:
·
|
developing
and executing internally generated growth
projects;
|
·
|
executing
strategic acquisitions related to gathering, processing, fractionating,
storing, transporting and marketing natural gas and NGLs that utilize its
core competencies; and
|
·
|
managing
its balance sheet over the long-term to maintain its investment-grade
credit ratings at or above their current
levels.
|
Description of Business - Our
ONEOK Partners segment is engaged in the gathering and processing of unprocessed
natural gas and fractionation of NGLs, primarily in the Mid-Continent, and Rocky
Mountain regions covering Oklahoma, Kansas, Montana, North Dakota and
Wyoming. These operations include the gathering of unprocessed
natural gas produced from crude oil and natural gas wells. Through
gathering systems, unprocessed natural gas is aggregated and treated or
processed for removal of water vapor, solids and other contaminants, and to
extract NGLs in order to provide marketable natural gas, commonly referred to as
residue gas. 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 stream is then separated by a
distillation process, referred to as fractionation, into marketable product
components such as ethane, ethane/propane (EP),
propane,
iso-butane, normal butane and natural gasoline (collectively, NGL
products). These NGL products can then be stored, transported and
marketed to a diverse customer base of end-users.
Revenue
from the gathering and processing business is primarily derived from the
following three types of contracts:
·
|
Percent
of Proceeds - ONEOK Partners retains a percentage of the NGLs and/or a
percentage of the residue gas as payment for gathering, compressing and
processing the producer’s unprocessed natural gas. For 2008,
this type of contract represented approximately 34 percent of contracted
volumes.
|
·
|
Fee
- ONEOK Partners is paid a fee for the services provided based on Btus
gathered, compressed and/or processed. For 2008, this type of
contract represented approximately 58 percent of contracted
volumes.
|
·
|
Keep-Whole
- ONEOK Partners extracts NGLs from unprocessed natural gas and returns to
the producer volumes of residue gas containing the same amount of Btus as
the unprocessed natural gas that was originally delivered. For
2008, this type of contract represented approximately 8 percent of
contracted volumes, with approximately 89 percent of that contracted
volume containing language that effectively converts these contracts into
fee contracts when the gross processing spread is
negative.
|
ONEOK
Partners also gathers, treats, fractionates, transports and stores
NGLs. ONEOK Partners’ natural gas liquids gathering pipelines deliver
unfractionated NGLs gathered from natural gas processing plants located in
Oklahoma, Kansas, the Texas panhandle and the Rocky Mountain region to
fractionators it owns in Oklahoma, Kansas, and Texas. The NGLs are
then separated through the fractionation process into the individual NGL
products that realize the greater economic value of the NGL
components. The individual NGL products are then stored or
distributed to petrochemical manufacturers, heating fuel users, refineries and
propane distributors through ONEOK Partners’ distribution pipelines that move
NGL products from Oklahoma and Kansas to the market centers in Conway, Kansas,
and Mont Belvieu, Texas, as well as the Midwest markets near Chicago,
Illinois.
Revenue
for the natural gas liquids businesses is primarily derived from the following
types of services:
·
|
Exchange
services - ONEOK Partners gathers and transports unfractionated NGLs to
its fractionators, separating them into marketable products and
redelivering the NGL products to its customers for a
fee;
|
·
|
Optimization
and marketing - ONEOK Partners uses its asset base, portfolio of contracts
and market knowledge to capture location and seasonal price differentials
through transactions that optimize the flow of its NGL products between
the major market centers in Conway, Kansas, and Mont Belvieu, Texas, as
well as markets near Chicago,
Illinois;
|
·
|
Isomerization
- ONEOK Partners converts normal butane to the more valuable iso-butane
used by the refining industry to increase the octane of motor
gasoline;
|
·
|
Storage
services - ONEOK Partners stores NGLs for a fee;
and
|
·
|
Transportation
- ONEOK Partners transports NGLs under its FERC-regulated
tariffs.
|
ONEOK
Partners operates interstate and intrastate natural gas transmission pipelines,
natural gas storage facilities and non-processable natural gas gathering
facilities. ONEOK Partners also provides natural gas transportation
and storage services in accordance with Section 311(a) of the Natural Gas Policy
Act. ONEOK Partners’ interstate assets transport natural gas through
FERC-regulated interstate natural gas pipelines that access supply from Canada
and from the Mid-Continent, Rocky Mountain and Gulf Coast
regions. ONEOK Partners’ pipelines include Midwestern Gas
Transmission, Guardian Pipeline, Viking Gas Transmission Company, OkTex Pipeline
Company L.L.C. and a 50 percent ownership interest in Northern Border
Pipeline.
ONEOK
Partners’ intrastate natural gas pipeline assets in Oklahoma have access to the
major natural gas producing areas and transport natural gas throughout the
state. ONEOK Partners also has access to the major natural gas
producing area in south central Kansas. In Texas, its 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 east to the
Houston Ship Channel market, north into the Mid-Continent market and west to the
California market. ONEOK Partners owns or leases storage capacity in
underground natural gas storage facilities in Oklahoma, Kansas and
Texas. ONEOK Partners’ natural gas pipeline assets primarily serve
LDCs, large industrial companies, municipalities, irrigation customers, power
generation facilities and marketing companies.
ONEOK
Partners’ revenues from its natural gas pipelines are typically derived from fee
services under the following types of contracts:
·
|
Firm
service - Customers can reserve a fixed quantity of pipeline or storage
capacity for the terms of their contracts. Under this type of
contract, the customer pays a fixed fee for a specified quantity
regardless of their actual usage, and is generally guaranteed access to
the capacity they reserve; and
|
·
|
Interruptible
service - Customers with interruptible service transportation and storage
agreements may utilize available capacity after firm service requests are
satisfied or on an as available basis. Under the interruptible
service contract, the customer is not guaranteed use of our pipelines and
storage facilities unless excess capacity is
available.
|
The main
factors that affect ONEOK Partners’ margins are:
·
|
NGL
transportation and fractionation volumes and associated
fees;
|
·
|
natural
gas transportation and storage
volumes;
|
·
|
weather
impacts on demand and operations;
|
·
|
fees
charged for processing services and storage
services;
|
·
|
the
Mid-Continent, Gulf Coast and Rocky Mountain natural gas price, crude oil
price and the daily average OPIS price for its products sold, as well as
the relative value on a Btu basis of each of the components to each
other;
|
·
|
the
relative value of ethane to natural gas;
and
|
·
|
regional
and seasonal natural gas and NGL product price
differentials.
|
Market Conditions and
Seasonality - Supply - ONEOK
Partners’ business is affected by the economy, commodity price volatility, and
weather. The strength of the economy has a direct relationship on
manufacturing and industrial companies’ demand for natural gas and NGL
products. Volatility in the commodity markets impacts the decisions
of ONEOK Partners’ customers relating to the output of the gas processing
plants, storage activity for natural gas and natural gas liquids, and demand for
the various NGL products. In addition, its natural gas liquids
pipelines and fractionation facilities are affected by operational or
market-driven changes in the output of the gas processing plants to which they
are connected. Natural gas and NGL output from gas processing plants
may increase or decrease affecting the quality of natural gas and volume of NGLs
transported through the systems as a result of the gross processing spread,
which is the difference between the relative value of the composite price of
NGLs to the price of natural gas, primarily ethane to natural gas. In
addition, volume delivered through the system may increase or decrease as a
result of the relative NGL price between the Mid-Continent and Gulf Coast
regions. Natural gas transportation throughput fluctuates due to
rainfall that impacts irrigation demand, hot temperatures that affect power
generation demand and cold temperatures that affect heating demand.
Natural
gas and NGL supply is affected by rig availability, operating capability and
producer drilling activity, which is sensitive to commodity prices, exploration
success, available capital and regulatory control. Relatively high
natural gas and crude oil prices, resulted in increased drilling for most of
2008 in the Mid-Continent and Rocky Mountain regions, which are our primary
supply regions. Significant price declines and reduced drilling
activity starting in the fourth quarter of 2008 are now creating less favorable
near-term supply projections.
Demand - Demand for gathering
and processing services is typically aligned with the supply of natural gas,
which generally flows from a producing area at a relatively steady but gradually
declining pace over time unless new reserves are added. ONEOK
Partners’ plant operations can be adjusted to respond to market conditions, such
as demand for ethane. By changing operating parameters at certain
plants, ONEOK Partners can produce more of the specific commodity that has the
most favorable price or price spread.
Demand
for natural gas 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 price volatility. The effect of weather on ONEOK
Partners’ natural gas pipelines operations is discussed below under
“Seasonality.” The strength of the economy directly impacts
manufacturing and industrial companies that rely on natural
gas. Commodity price volatility can influence customers’ decisions
related to the usage of natural gas versus alternative fuels and natural gas
storage injection and withdrawal activity.
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
natural gas liquids gathering, fractionation and distribution
services. Natural gas and propane are subject to weather-related
seasonal demand.
Other
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. Ethane and EP are used by the petrochemical industry to produce
chemical products, such as plastic, rubber and synthetic fiber.
Commodity Prices -
During 2008, both crude oil and natural gas prices were volatile, with NYMEX
crude oil settlement prices ranging from $49.62 to $134.62 per Bbl and NYMEX
natural gas settlement prices ranging from $6.47 to $13.11 per
MMBtu.
Seasonality - Some of
ONEOK Partners’ products, such as natural gas and propane used for heating, are
subject to seasonality, resulting in more demand during the months of November
through March. As a result, prices of these products are typically
higher during that time period. Demand has also increased for natural
gas in the summer periods as more electric generation is now dependent upon
natural gas for fuel. Other products, such as ethane and EP, are tied
to the petrochemical industry, while normal butane, iso-butane and natural
gasoline are used by the refining industry as blending stocks. As a
result, the prices of these products are affected by the economic conditions and
demand associated with these various industries.
Competition - ONEOK
Partners’ natural gas and natural gas liquids pipelines compete directly with
other intrastate and interstate pipeline companies and other storage facilities
for natural gas and NGLs. 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. Competition
among pipelines and storage facilities is based primarily on fees for services,
quality of services provided, current and forward natural gas prices and
proximity to supply areas and markets. ONEOK Partners believes that
its pipelines and storage assets enable it to effectively compete.
ONEOK
Partners’ natural gas gathering and processing business competes for natural gas
supplies with major integrated exploration and production companies, 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. ONEOK Partners’ gathering and fractionation
business competes with other fractionators, storage providers and gatherers for
NGL supplies in the Rocky Mountain, Mid-Continent and Gulf Coast
regions. The factors that typically affect ONEOK Partners’ ability to
compete for natural gas and NGL supplies are:
·
|
producer
drilling activity;
|
·
|
the
petrochemical industry’s level of capacity utilization and feedstock
requirements;
|
·
|
fees
charged under our contracts;
|
·
|
pressures
maintained on our gathering
systems;
|
·
|
location
of our gathering systems relative to our
competitors;
|
·
|
location
of our gathering systems relative to drilling
activity;
|
·
|
efficiency
and reliability of our operations;
and
|
·
|
delivery
capabilities that exist in each system, plant and storage
location.
|
ONEOK
Partners is responding to these industry conditions by making capital
investments to access new supplies, increase gathering and fractionation
capacity, increase storage capabilities, improve plant processing flexibility
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.
Government Regulation - The
FERC has traditionally maintained that a processing plant is not a facility for
the transportation or sale for resale of natural gas in interstate commerce and,
therefore, is not subject to jurisdiction under the Natural Gas
Act. Although the FERC has made no specific declaration as to the
jurisdictional status of ONEOK Partners’ natural gas processing operations or
facilities, ONEOK Partners’ natural gas processing plants are primarily involved
in removing NGLs and, therefore, ONEOK Partners believes, its natural gas
processing plants are exempt from FERC jurisdiction. The Natural Gas
Act also exempts natural gas gathering facilities from the jurisdiction of the
FERC. Interstate transmission facilities remain subject to FERC
jurisdiction. The FERC has historically distinguished between these
two types of facilities, either interstate or intrastate, on a fact-specific
basis. ONEOK Partners believes its gathering facilities and
operations meet the criteria used by the FERC for non-jurisdictional gathering
facility status. ONEOK Partners can transport residue gas from its
plants to interstate pipelines in accordance with Section 311(a) of the Natural
Gas Policy Act.
Oklahoma
and Kansas also have statutes regulating, in 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.
ONEOK
Partners’ interstate natural gas pipelines are regulated under the Natural Gas
Act and Natural Gas Policy Act, which give the FERC jurisdiction to regulate
virtually all aspects of the pipeline activities. ONEOK Partners’
intrastate natural gas transportation assets in Oklahoma, Kansas and Texas are
regulated by the OCC, KCC and RRC, respectively. ONEOK Partners has
flexibility in establishing natural gas transportation rates with
customers. However, there are maximum rates that ONEOK Partners can
charge its customers in Oklahoma and Kansas.
ONEOK
Partners’ proprietary natural gas liquids gathering pipelines in both Oklahoma
and Kansas are not regulated by the FERC or the states’ respective corporation
commissions. ONEOK Partners’ remaining natural gas liquids gathering
and
distribution
pipelines are interstate pipelines regulated by the FERC. ONEOK
Partners transports unfractionated NGLs and NGL products pursuant to filed
tariffs.
Additionally,
the operations of our assets are regulated by various state and federal
government agencies. See further discussion in the “Environmental and
Safety Matters” section.
Unconsolidated Affiliates -
Our ONEOK Partners segment has the following unconsolidated
affiliates:
·
|
50
percent interest in Northern Border Pipeline, which transports natural gas
from the Montana-Saskatchewan border near Port Morgan, Montana, to a
terminus near North Hayden,
Indiana;
|
·
|
49
percent ownership interest in Bighorn Gas Gathering, L.L.C., which
operates a major coalbed methane gathering system serving a broad
production area in northeast
Wyoming;
|
·
|
37
percent ownership interest in Fort Union Gas Gathering, which gathers
coalbed methane gas produced in the Powder River Basin and delivers
natural gas into the interstate pipeline
grid;
|
·
|
35
percent ownership interest in Lost Creek Gathering Company, L.L.C., which
gathers natural gas produced from conventional wells in the Wind River
Basin of central Wyoming and delivers natural gas into the interstate
pipeline grid;
|
·
|
10
percent ownership interest in Venice Energy Services Co., LLC, a gas
processing complex near Venice,
Louisiana;
|
·
|
50
percent ownership interest in Chisholm Pipeline Company which operates an
interstate natural gas liquids pipeline system extending approximately 184
miles from origin points in Oklahoma and
Kansas;
|
·
|
48
percent ownership interest in Sycamore Gas System, which is a gathering
system with compression located in south central Oklahoma;
and
|
·
|
50
percent ownership interest in the Heartland joint venture, which operates
a terminal and pipeline systems that transport refined petroleum products
in Kansas, Nebraska and Iowa.
|
See Note
O of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K for additional discussion of unconsolidated affiliates.
Distribution
Business Strategy - Our Distribution segment
focuses on increasing the level of sustainable earnings through safe, reliable,
environmentally sound and legally compliant distribution
operations.
The
integrated strategy for our LDCs incorporates:
·
|
a
rates and regulatory strategy that includes fostering positive
relationships with regulators, consistent strategies and synchronized rate
case filings;
|
·
|
a
focus on the growth of our customer count and rate base through efficient
investment in our system while emphasizing safety and cost control;
and
|
·
|
providing
customer choice programs designed to reduce volumetric sensitivity and
create value for our customers.
|
Our
regulatory strategy incorporates rate features that provide strategies for
earnings lag, margin protection and risk mitigation. These strategies
include capital recovery mechanisms in Oklahoma, Kansas and portions of
Texas. In Texas, we also have cost of service adjustments that
address investments in rate base and changes in expense. Margin
protection strategies include increased customer fixed charges in all three
states. Risk mitigation strategies include fuel related bad-debt
recovery mechanisms in Oklahoma, Kansas and portions of Texas.
Description of Business - Our
Distribution segment provides natural gas distribution services to more than two
million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas,
Kansas Gas Service and Texas Gas Service, respectively, each a division of
ONEOK. We serve residential, commercial, industrial and
transportation customers in all three states. In addition, our
distribution companies in Oklahoma and Kansas serve wholesale customers, and in
Texas we serve public authority customers, such as cities, governmental agencies
and schools.
Our
operating results are primarily affected by the number of customers, usage and
the ability to collect delivery rates that provide a reasonable rate of return
on our investment and recovery of our cost of service. Natural gas
costs are passed through to our customers based on the actual cost of gas
purchased by the respective distribution companies. Substantial
fluctuations in natural gas sales can occur from year to year without materially
or adversely impacting our net margin, since the fluctuations in natural gas
costs affect natural gas sales and cost of gas by an equivalent
amount. Higher natural gas costs may cause customers to conserve or,
in the case of industrial customers, to use alternative energy
sources. Higher natural gas costs may also adversely impact our
accounts receivable collections, resulting in higher bad-debt
expense.
The rate
structure for Oklahoma Natural Gas includes two service rate options for
residential gas sales customers. Certain high usage customers pay a
higher monthly service charge and a lower per dekatherm delivery charge, while
lower usage customers pay a lower monthly service charge coupled with a higher
per dekatherm delivery charge. Customers can elect to change service
rate options to ensure that they are billed under the alternative that best fits
their individual usage, but they must remain on the selected option for a full
year after the change is made.
Oklahoma
Natural Gas, Kansas Gas Service and Texas Gas Service distribute natural gas as
public utilities to approximately 87 percent, 70 percent and 14 percent of the
distribution markets for Oklahoma, Kansas and Texas,
respectively. Natural gas sold to residential and commercial
customers accounts for approximately 79 and 20 percent of natural gas sales,
respectively, in Oklahoma; 74 and 19 percent of natural gas sales, respectively,
in Kansas; and 66 and 26 percent of natural gas sales, respectively, in
Texas.
A
franchise, although nonexclusive, is a utility’s right to use the municipal
streets, alleys and other public ways for a defined period of time in exchange
for a fee. In management’s opinion, our franchises contain no unduly
burdensome restrictions and are sufficient for the transaction of business in
the manner in which it is now conducted.
Market Conditions and
Seasonality - Supply - In 2008, our
Distribution segment purchased 182 Bcf of natural gas supply. Our gas
supply portfolio consists of long-term, seasonal and short-term contracts from a
diverse group of suppliers. These contracts are awarded through
competitive bid processes to ensure reliable and competitively priced gas
supply. Our Distribution segment’s natural gas supply is purchased
from a combination of direct wellhead production, natural gas processing plants,
natural gas marketers and production companies.
We are
responsible for acquiring sufficient natural gas supplies, interstate and
intrastate pipeline capacity and storage capacity to meet customer
requirements. As such, we must contract for both reliable and
adequate supplies and delivery capacity to our distribution system, while
considering: (i) the dynamics of the
interstate and intrastate pipeline and storage capacity market; (ii) our peaking
facilities and storage and contractual commitments; and (iii) the demand
characteristics of our customer base.
An
objective of our supply sourcing strategy is to diversify our supply among
multiple production areas and suppliers. This strategy is designed to
protect receipt of supply from being curtailed by physical interruption,
possible financial difficulties of a single supplier, natural disasters and
other unforeseen force majeure events.
There is
an adequate supply of natural gas available to our utility systems, and we do
not anticipate problems with securing additional natural gas supply as needed
for our customers. However, if supply shortages occur, each of our
LDCs has curtailment tariff provisions in place that provide for: (i) reducing
or discontinuing gas service to large industrial users; and (ii) requesting that
residential and commercial customers reduce their gas requirements to an amount
essential for public health and safety. In addition, during times of
critical supply problems, curtailments of deliveries to customers with firm
contracts may be made in accordance with guidelines established by appropriate
federal, state and local regulatory agencies.
Natural
gas supply requirements are affected by changes in the natural gas consumption
pattern of our customers that are driven by factors other than
weather. Natural gas usage per customer may decline as customers
change their consumption patterns in response to: (i) more volatile and higher
natural gas prices, as discussed above; (ii) customers’ replacement
of older, less efficient gas appliances with more efficient appliances; (iii)
more energy-efficient construction; and (iv) fuel switching. In each
jurisdiction in which we operate, changes in customer usage profiles have been
reflected in recent rate case proceedings where rates have been adjusted to
reflect current customer usage.
In
December 2007, Oklahoma Natural Gas was authorized by the OCC to implement a
natural gas hedging program as a three-year pilot program, with up to $10
million per year in hedge costs to be recovered from
customers. Kansas Gas Service has a natural gas hedging program in
place, subject to annual KCC approval, which is designed to reduce volatility in
the natural gas price paid by consumers. The costs of this program
are borne by the Kansas Gas Service customers. Texas Gas Service also
has a natural gas hedging program for certain of its jurisdictions.
In
managing our gas supply portfolios, we partially mitigate gas price volatility
using a combination of financial derivatives, the triggering of forward prices
on certain gas supply contracts, and injecting gas into leased storage
capacity. Our Distribution segment does not utilize financial
derivatives for speculative purposes, nor does it have trading
operations. To further mitigate gas price volatility, we utilize 38.3
Bcf of leased storage capacity, which allows gas to be purchased during the
off-peak season and stored for use in the winter periods.
Demand - See
discussion below under “Seasonality” and “Competition” for factors affecting
demand.
Seasonality - Natural
gas sales to residential and commercial customers are seasonal, as a substantial
portion of their natural gas is used for space heating. Accordingly,
the volume of natural gas sales is normally higher during the heating season
(November through March) than in other months of the year. The sales
effect resulting from weather that is above or below normal is substantially
offset through weather normalization adjustments (WNA), which are now approved
by the regulatory authorities for all of our Oklahoma and Kansas service
territories. WNA allows us to increase customer billing to offset
lower gas usage when weather is warmer than normal and decrease customer billing
to offset higher gas usage when weather is colder than normal.
Approximately
94 percent of Texas Gas Service’s revenues, including Austin and Galveston, are
protected from abnormal weather due to a higher customer charge or WNA
clauses. A higher customer charge is included in the authorized rate
design for the jurisdictions of El Paso, north Texas, Rio Grande Valley and Port
Arthur to protect customers from abnormal rate fluctuation due to
weather.
Competition - We can face competition
based on customers’ preference for natural gas compared with other energy
products, and the comparative prices of those products. The most
significant product competition occurs between natural gas and electricity in
the residential and small commercial markets. We compete for space
heating, water heating, cooking and other general energy needs. Customers
and builders typically make the decision for the type of equipment to install at
initial installation and use the chosen energy source for the life of the
equipment. The markets in our service territories have become increasingly
competitive. Changes in the competitive position of natural gas
relative to electricity and other energy products have the potential of causing
a decline in the number of future natural gas customers.
We
believe that we must maintain a competitive advantage in order to retain our
customers, and, accordingly, we focus on providing safe, reliable, efficient
service and controlling costs. Our Distribution segment is subject to
competition from other pipelines for our existing industrial
load. Oklahoma Natural Gas, Kansas Gas Service and Texas Gas Service
compete for service to large industrial and commercial customers, and
competition has and may continue to impact margins.
Under our
transportation tariffs, qualifying industrial and commercial customers are able
to purchase their natural gas commodity from the supplier of their choice and
have us transport it for a fee. A portion of transportation services
provided is at negotiated rates that are generally below the maximum approved
transportation tariff rates. Reduced rate transportation service may
be negotiated when a competitive pipeline is in proximity or another viable
energy option is available. Increased competition could potentially
lower these rates. Texas Gas Service files all negotiated
transportation service contracts under a separate, confidential tariff at
the RRC.
Government Regulation - Rates
charged by our Distribution segment for natural gas services are established by
the OCC for Oklahoma Natural Gas and by the KCC for Kansas Gas
Service. Texas Gas Service is subject to regulatory oversight by the
various municipalities that it serves, which have primary jurisdiction in their
respective areas. Rates in unincorporated areas and all appellate
matters are subject to regulatory oversight by the RRC. Natural gas
purchase costs are included in the Purchased Gas Adjustment (PGA) clause rate
that is billed to customers. Our distribution companies do not make a
profit on the cost of gas. Other changes in costs must be recovered
through periodic rate adjustments approved by the OCC, KCC, RRC and various
municipalities in Texas. See page 49 for a detailed description of
our various regulatory initiatives.
Oklahoma
Natural Gas has settled all known claims arising out of long-term gas supply
contracts containing “take-or-pay” provisions that purport to require us to pay
for volumes of natural gas contracted for but not taken. The OCC has
previously authorized recovery of the accumulated settlement costs over a
20-year period expiring in 2014, or approximately $7.0 million annually, through
a combination of a surcharge from customers, revenue from transportation under
Section 311(a) of the Natural Gas Policy Act and other intrastate transportation
revenues.
Additionally,
the operations of our assets are regulated by various state and federal
government agencies. See further discussion in the “Environmental and
Safety Matters” section.
Energy
Services
Business Strategy - Our Energy
Services segment utilizes our network of contracted gas supply and leased
transportation and storage assets to provide premium services to our
customers. The asset positions afford us the flexibility to develop
innovative, customer-specific demand delivery services for those we serve, at a
competitive cost. With these services and a focus on customer
relationships, we expect to attract new customers and retain existing customers
that generate recurring margins.
We follow
a strategy of optimizing our storage and cross-regional transportation capacity
through the application of market knowledge and effective risk
management. We maximize value by actively hedging the time and
locational spread risks that are inherent to storage and transportation
contracts and will pursue hedging strategies that effectively mitigate these
risks. At the same time, we capitalize on opportunities created by
market volatility, weather-related events, supply-demand imbalances and market
liquidity inefficiency, which allows us to capture additional
margin. Using market information, we manage these asset-based
positions and seek to provide incremental margin in our trading
portfolio.
Through
our wholesale marketing and risk management capabilities, we are able to be a
full-service provider in our retail operations. We are able to offer
a broad range of products and are expanding our markets. We plan to
grow our retail business through internal growth initiatives, as well as
expansion into areas that allow retail unbundling. We manage the
commodity price and volumetric risk in these operations through a variety of
risk management and hedging activities.
It is our
intention to minimize the mark-to-market earnings impact that our forward hedges
have on current period earnings. When possible, we implement effective hedging
strategies using derivative instruments that qualify as hedges under Statement
133, “Accounting for Derivative Instruments and Hedging Activities,” (Statement
133).
Our
Energy Services segment requires working capital to purchase natural gas
inventory and to meet cash collateral requirements associated with our risk
management activities. Our inventory purchases and hedging strategies
are implemented with consideration given to ONEOK’s overall working capital
requirements and liquidity. Restrictions on our access to working
capital may impact our inventory purchases and risk management activities, which
could impact our results.
We are
assessing the ongoing capital requirements of the wholesale energy business,
which includes evaluating our contracted storage and
transportation. This review is focused on ensuring our contracted
assets continue to be aligned with our key strategy of providing
customer-specific premium delivery services that generate recurring demand
revenues and margins.
Description of Business - Our
Energy Services segment’s primary focus is to create value for our customers by
delivering physical natural gas products and risk management services through
our network of contracted transportation and storage capacity and natural gas
supply. These services include meeting our customers’ baseload, swing
and peaking natural gas commodity requirements on a year-round
basis. Our contracted storage and transportation capacity connects
major supply and demand centers throughout the United States and into
Canada. With these contracted assets, our business strategies include
identifying, developing and delivering specialized premium products and services
valued by our customers, which are primarily LDCs, electric utilities, and
commercial and industrial end users. Our storage and transportation
capacity allows us opportunities to optimize value through our application of
market knowledge and risk management skills.
We
actively manage the commodity price and volatility risks associated with
providing energy risk management services to our customers by executing
derivative instruments in accordance with the parameters established in our
commodity risk management policy. The derivative instruments consist
of over-the-counter transactions such as forward, swap and option contracts, and
NYMEX futures and option contracts.
Numerous
risk management opportunities and operational strategies exist that can be
implemented through the use of storage facilities and transportation
capacity. We utilize our industry knowledge and expertise in order to
capitalize on opportunities that are provided through market
volatility. We utilize our experience to optimize the value of our
contracted assets, and we use our risk management and marketing capabilities to
both manage risk and to generate additional margins. We apply a
combination of cash flow and fair value hedge accounting when implementing
hedging strategies that take advantage of favorable market
conditions. See Note D of the Notes to Consolidated Financial
Statements in this Annual Report on Form 10-K for additional
information. Additionally, certain non-trading transactions, which
are economic hedges of our accrual transactions, such as our storage and
transportation contracts, will not qualify for hedge accounting
treatment. These economic hedges receive mark-to-market accounting
treatment, as they are derivative contracts and are not designated as part of a
hedge relationship. As a result, the underlying risk being hedged
receives accrual accounting treatment, while we use
mark-to-market
accounting treatment for the economic hedges. We cannot predict the
earnings fluctuations from mark-to-market accounting, and the impact on earnings
could be material.
Our
working capital requirements related to our inventory in storage peaked in
August 2008, with 61.0 Bcf valued at $614.6 million; this balance had decreased
to $451.7 million by December 31, 2008. During September 2008, we
impaired our inventory value; were it not for this impairment, our highest
inventory balance would have been in November 2008 with 84.3 Bcf in
storage. In addition, margin requirements can result in increased
working capital requirements. During 2008, our margin requirements
with counterparties ranged from zero to $378 million.
Market Conditions and
Seasonality - Supply - During
periods of high natural gas demand, we utilize storage capacity to supplement
natural gas supply volumes to meet our peak day demand obligations or market
needs.
Demand - Demand met
by our swing and peaking natural gas requirements contracts in our wholesale
operation is driven by the extent to which temperatures vary from normal
levels. A significant portion of this business is contracted during
the winter period of November through March. Our retail business’
demand for natural gas is primarily driven by the use of space heating and is
significantly impacted by temperature variations.
Seasonality - Due to
seasonality of natural gas consumption, storage withdrawals and demand for our
products and services, earnings are normally higher during the winter months
than the summer months. Our Energy Services segment’s margins are
subject to fluctuations during the year, primarily due to the impact certain
seasonal factors have on sales volumes and the price of natural
gas. Natural gas sales volumes are typically higher in the winter
heating months than in the summer months, reflecting increased demand due to
greater heating requirements and, typically, higher natural gas
prices.
Competition - The recent market
conditions affecting credit and liquidity have impacted competition by causing
some of our competitors, including financial institutions, to either exit the
business or scale back their operations. In response to a competitive
marketing environment, our strategy is to concentrate our efforts on providing
reliable service during peak demand periods and capturing opportunities created
by short-term pricing volatility. We can effectively compete in the
market by utilizing our leased storage and transportation assets. We
continue to focus on building and strengthening supplier and customer
relationships to execute our strategy and increase our market
presence.
Other
Description of Business - The
primary companies in our Other segment include ONEOK Leasing Company and ONEOK
Parking Company, L.L.C.
Through
ONEOK Leasing Company and ONEOK Parking Company, L.L.C., we own a parking garage
and an office building (ONEOK Plaza) in downtown Tulsa, Oklahoma, where our
headquarters are located. ONEOK Leasing Company leases excess office
space to others and operates our headquarters office building. ONEOK
Parking Company, L.L.C. owns and operates a parking garage adjacent to our
headquarters.
In July
2007, ONEOK Leasing Company gave notice of its intent to exercise its option to
purchase ONEOK Plaza on or before the end of the lease term that was set to
expire on September 30, 2009. In March 2008, ONEOK Leasing Company,
purchased ONEOK Plaza for a total purchase price of approximately $48 million,
which included $17.1 million for the present value of the remaining lease
payments and $30.9 million for the base purchase price.
ENVIRONMENTAL
AND SAFETY MATTERS
Information
about our environmental matters is included in Note K of the Notes to
Consolidated Financial Statements in this Annual Report on Form
10-K.
Pipeline Safety - We are
subject to United States Department of Transportation regulations, including
integrity management regulations. The Pipeline Safety Improvement Act
requires pipeline companies to perform integrity assessments on pipeline
segments that pass through densely populated areas or near specifically
designated high consequence areas. To our knowledge, we are in
compliance with all material requirements associated with the various pipeline
safety regulations.
Air and Water Emissions - The
federal Clean Air Act, the federal Clean Water Act and analogous state laws
impose restrictions and controls regarding the discharge of pollutants into the
air and water in the United States. Under the Clean Air Act, a
federally enforceable operating permit is required for sources of significant
air emissions. We may be required to incur certain capital
expenditures for air pollution-control equipment in connection with obtaining or
maintaining permits and approvals for sources of air emissions. The
Clean Water Act imposes substantial potential liability for the removal
of
pollutants
discharged to waters of the United States and remediation of waters affected by
such discharge. To our knowledge, we are in compliance with all
material requirements associated with the various regulations.
The
United States Congress is actively considering legislation to reduce emissions
of greenhouse gases, including carbon dioxide and methane. In
addition, state and regional initiatives to regulate greenhouse gas emissions
are underway. We are monitoring federal and state legislation to
assess the potential impact on our operations. Our most recent
calculation of direct greenhouse gas emissions for ONEOK and ONEOK Partners is
estimated to be less than 6 million metric tons of carbon dioxide equivalents on
an annual basis. We will continue efforts to quantify our direct
greenhouse gas emissions and will report such emissions as required by any
mandatory reporting rule, including the rules anticipated to be issued by the
EPA in mid-2009.
Superfund - The Comprehensive
Environmental Response, Compensation and Liability Act, also known as CERCLA or
Superfund, imposes liability, without regard to fault or the legality of the
original act, on certain classes of persons who contributed to the release of a
hazardous substance into the environment. These persons include the
owner or operator of a facility where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
facility. Under CERCLA, these persons may be liable for the costs of
cleaning up the hazardous substances released into the environment, damages to
natural resources and the costs of certain health studies.
Chemical Site Security - The
United States Department of Homeland Security (Homeland Security) released an
interim rule in April 2007 that requires companies to provide reports on sites
where certain chemicals, including many hydrocarbon products, are
stored. We completed the Homeland Security assessments and our
facilities were subsequently assigned to one of four risk-based tiers ranging
from high (Tier 1) to low (Tier 4) risk, or not tiered at all due to low
risk. A majority of our facilities were not tiered. We are
waiting for Homeland Security’s analysis to determine if any of the tiered
facilities will require Site Security Plans and possible physical security
enhancements.
Climate Change - 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 rules anticipated to be issued by the EPA in mid-2009;
(ii) improving the efficiency of our various pipelines, natural gas processing
facilities and natural gas liquids fractionation facilities; (iii) following
developing technologies for emission control; (iv) following developing
technologies to capture carbon dioxide to keep it from reaching the atmosphere;
and (v) analyzing options for future energy investment.
Currently,
certain subsidiaries of ONEOK Partners participate in the Processing and
Transmission sectors and LDCs in our Distribution segment participate in the
Distribution sector of the EPA’s Natural Gas STAR Program to voluntarily reduce
methane emissions. A subsidiary in our ONEOK Partners’ segment was
honored in 2008 as the “Natural Gas STAR Gathering and Processing Partner of the
Year” for its 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 during pipeline and facility
maintenance and operations. Our most recent calculation of our annual
lost-and-unaccounted-for natural gas, for all of our business operations, is
less than 1 percent of total throughput.
EMPLOYEES
We
employed 4,742 people at January 31, 2009, including 739 people employed by
Kansas Gas Service, who were subject to collective bargaining
contracts. The following table sets forth our contracts with
collective bargaining units at January 31, 2009.
Union
|
Employees
|
Contract
Expires
|
United
Steelworkers of America
|
414
|
|
|
June
30, 2009
|
International
Union of Operating Engineers
|
13
|
|
|
June
30, 2009
|
International
Brotherhood of Electrical Workers
|
312
|
|
|
June
30, 2010
|
EXECUTIVE
OFFICERS
All
executive officers are elected at the annual meeting of our Board of Directors
and serve for a period of one year or until successors are duly
elected. Our executive officers listed below include the officers who
have been designated by our Board of Directors as our Section 16 executive
officers.
Name
and Position
|
Age
|
Business
Experience in Past Five Years
|
John
W. Gibson
|
56
|
2007
to present
|
Chief
Executive Officer
|
Chief
Executive Officer
|
|
2006
to present
|
Member
of the Board of Directors
|
and
Member of the Board of Directors
|
|
2006
|
President
and Chief Operating Officer of ONEOK Partners, L.P.
|
|
|
2005
to 2006
|
President,
ONEOK Energy Companies
|
|
|
2000
to 2005
|
President,
Energy
|
Jim
Kneale
|
57
|
2007
to present
|
President
and Chief Operating Officer
|
President
and Chief Operating Officer
|
|
2004
to 2006
|
Executive
Vice President - Finance and Administration and Chief Financial
Officer
|
|
|
2001
to 2004
|
Senior
Vice President, Treasurer and Chief Financial Officer
|
Curtis
L. Dinan
|
41
|
2007
to present
|
Senior
Vice President, Chief Financial Officer and Treasurer
|
Senior
Vice President,
|
|
2004
to 2006
|
Senior
Vice President and Chief Accounting Officer
|
Chief
Financial Officer and Treasurer
|
|
2004
|
Vice
President and Chief Accounting Officer
|
|
|
2002
to 2004
|
Assurance
and Business Advisory Partner, Grant Thornton, LLP
|
John
R. Barker
|
61
|
2004
to present
|
Senior
Vice President and General Counsel
|
Senior
Vice President and
|
|
1994
to 2004
|
Stockholder,
President and Director, Gable & Gotwals
|
General
Counsel
|
|
|
|
Caron
A. Lawhorn
|
47
|
2007
to present
|
Senior
Vice President and Chief Accounting Officer
|
Senior
Vice President and
|
|
2005
to 2006
|
Senior
Vice President, Financial Services and Treasurer
|
Chief
Accounting Officer
|
|
2004
to 2005
|
Vice
President and Controller
|
|
|
2003
to 2004
|
Vice
President of Audit and Risk
Control
|
No family
relationships exist between any of the executive officers, nor is there any
arrangement or understanding between any executive officer and any other person
pursuant to which the officer was selected.
AVAILABLE
INFORMATION
We make
available on our Web site copies of our Annual Report on Form 10-K, 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, Corporate Governance
Guidelines and Director Independence Guidelines are also available on our Web
site, and we will make available, free of charge, copies of these documents upon
request. However, our Web site and any contents thereof are not
incorporated by reference into this document.
RISK
FACTORS INHERENT IN OUR BUSINESS
Current
levels of market volatility are unprecedented.
The
capital and credit markets have been experiencing volatility and
disruption. During the fourth quarter of 2008, the volatility and
disruption reached unprecedented levels. In many cases, the capital
markets have exerted downward pressure on equity prices and reduced the credit
capacity for certain companies. Our ability to grow could be
constrained if we do not have regular access to the capital and credit
markets. If current levels of market disruption and volatility
continue or worsen, 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 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 might
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 and results of operations.
The
recent downturn in the credit markets has increased the cost of borrowing and
has made financing difficult to obtain, each of which may have a material
adverse effect on our results of operations and business.
Recent
events in the financial markets have had an adverse impact on the credit
markets. As a result, credit has become more expensive and difficult
to obtain. Some lenders are imposing more stringent restrictions on
the terms of credit and there may be a general reduction in the amount of credit
available in the markets in which we conduct business. The
negative impact of the tightening of the credit markets may have a material
adverse effect on us resulting from, but not limited to, an inability to obtain
credit necessary to expand facilities or finance the acquisition of assets on
favorable terms, if at all, increased financing costs or financing with
increasingly restrictive covenants.
Our
cash flow depends heavily on the earnings and distributions of ONEOK
Partners.
Our
partnership interest in ONEOK Partners is one of our largest cash-generating
assets. Therefore, our cash flow is heavily dependent upon the
ability of ONEOK Partners to make distributions to its partners. A
significant decline in ONEOK Partners’ earnings and/or cash distributions would
have a corresponding negative impact on us. For information on the
risk factors inherent in the business of ONEOK Partners, see the section below
entitled “Risk Factors Related to ONEOK Partners’ Business” and the ONEOK
Partners 2008 Annual Report on Form 10-K.
Some
of our nonregulated businesses have a higher level of risk than our regulated
businesses.
Some of
our nonregulated operations, which include ONEOK Partners’ gathering and
processing, natural gas liquids gathering and fractionation, and our energy
services businesses, have a higher level of risk than our regulated operations,
which include our distribution and ONEOK Partners’ natural gas and natural gas
liquids pipelines businesses. We and ONEOK Partners expect to
continue investing in natural gas and natural gas liquids projects and other
related projects, some or all of which may involve nonregulated businesses or
assets. These projects could involve risks associated with
operational factors, such as competition and dependence on certain suppliers and
customers, and financial, economic and political factors, such as rapid and
significant changes in commodity prices, the cost and availability of capital
and counterparty risk, including the inability of a counterparty, customer or
supplier to fulfill a contractual obligation.
Our
LDCs have recorded certain assets that may not be recoverable from our
customers.
Accounting
policies for our LDCs permit certain assets that result from the regulatory
process to be recorded on our balance sheet that could not be recorded under
GAAP for nonregulated entities. We consider factors such as rate
orders from regulators, previous rate orders for substantially similar costs,
written approval from the regulators and analysis of recoverability from
internal and external legal counsel 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.
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.
Our
businesses are subject to market and credit risks.
We are
exposed to market and credit risks in all of our operations. To
minimize the risk of commodity price fluctuations, we periodically enter into
derivative transactions to hedge anticipated purchases and sales of natural gas,
NGLs, crude oil, fuel requirements and firm transportation
commitments. Interest-rate swaps are also used to manage
interest-rate risk. Currency
swaps are
used to mitigate unexpected changes that may occur in anticipated revenue
streams of our Canadian natural gas sales and purchases driven by currency rate
fluctuations. However, financial derivative instrument contracts do
not eliminate the risks. Specifically, such risks include commodity
price changes, market supply shortages, interest rate changes and counterparty
default. The impact of these variables could result in our inability
to fulfill contractual obligations, significantly higher energy or fuel costs
relative to corresponding sales contracts, or increased interest
expense.
We are
subject to the risk of loss resulting from nonpayment and/or nonperformance by
customers of our Energy Services segment. The customers of our Energy
Services segment are predominantly LDCs, industrial customers, natural gas
producers and marketers that 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 for our
services. Although we attempt to obtain adequate security for these
risks, if we fail to adequately assess the creditworthiness of existing or
future customers, unanticipated deterioration in their creditworthiness and any
resulting nonpayment and/or nonperformance could adversely impact results of
operations for our Energy Services segment. In addition, if any of
our Energy Services segment’s customers filed for bankruptcy protection, we may
not be able to recover amounts owed, which would negatively impact the results
of operations for our Energy Services segment.
Increased
competition could have a significant adverse financial impact on
us.
The
natural gas and natural gas liquids industries are expected to remain highly
competitive, resulting from deregulation and other initiatives being pursued by
the industry and regulatory agencies that allow customers increased options for
energy supplies and service. The demand for natural gas and NGLs is
primarily a function of commodity prices, including prices for alternative
energy sources, customer usage rates, weather, economic conditions and service
costs. Our ability to compete also depends on a number of other
factors, including competition from other pipelines for our existing load, the
efficiency, quality and reliability of the services we provide, and competition
for throughput for our gathering systems and plants.
We cannot
predict when we will be subject to changes in legislation or regulation, nor can
we predict the impact of these changes on our financial position, results of
operations or cash flows. Although we believe our businesses are
positioned to compete effectively in the energy market, there are no assurances
that this will be true in the future.
We
may not be able to successfully make additional strategic acquisitions or
integrate businesses we acquire into our operations.
Our
ability to successfully make strategic acquisitions and investments will depend
on: (i) the extent to which acquisitions and investment opportunities
become available; (ii) our success in bidding for the opportunities that do
become available; (iii) regulatory approval, if required, of the
acquisitions on favorable terms; and (iv) our access to capital, including
our ability to use our equity in acquisitions or investments, and the terms upon
which we obtain capital. If we are unable to make strategic
investments and acquisitions, we may be unable to grow. If we are
unable to successfully integrate new businesses into our operations, we could
experience increased costs and losses on our investments.
Acquisitions that appear to be
accretive may nevertheless reduce our cash from operations on a per share
basis.
Any
acquisition involves potential risks that may include, among other
things:
·
|
mistaken
assumptions about volumes, revenues and costs, including
synergies;
|
·
|
an
inability to successfully integrate the businesses we
acquire;
|
·
|
decrease
in our liquidity as a result of our using a significant portion of our
available cash or borrowing capacity to finance the
acquisition;
|
·
|
a
significant increase in our interest expense or financial leverage if we
incur additional debt to finance the
acquisition;
|
·
|
the
assumption of unknown liabilities for which we are not indemnified or for
which our indemnity is inadequate;
|
·
|
an
inability to hire, train or retain qualified personnel to manage and
operate the acquired business and
assets;
|
·
|
limitations
on rights to indemnity from the
seller;
|
·
|
mistaken
assumptions about the overall costs of equity or
debt;
|
·
|
the
diversion of management’s and employees’ attention from other business
concerns;
|
·
|
unforeseen
difficulties operating in new product areas or new geographic
areas;
|
·
|
increased
regulatory burdens;
|
·
|
customer
or key employee losses at an acquired business;
and
|
·
|
increased
regulatory requirements.
|
If we
consummate any future acquisitions, our capitalization and results of operations
may change significantly, and investors will not have the opportunity to
evaluate the economic, financial and other relevant information that we will
consider in determining the application of these funds and other
resources.
Any
reduction in our credit ratings could materially and adversely affect our
business, financial condition, liquidity and results of operations.
Our
long-term senior unsecured debt has been assigned an investment-grade rating by
S&P of “BBB” (Stable) and Moody’s of “Baa2” (Stable). However, 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 S&P or Moody’s 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
S&P or Moody’s were to downgrade the long-term ratings of ONEOK Partners
below investment grade, ONEOK Partners would, under certain circumstances, be
required to offer to repurchase certain of its senior notes.
Further, if our short-term ratings were to fall below A-2 (capacity to
meet its financial commitment on the obligation is satisfactory) or P-2 (strong
ability to repay short-term debt obligations), the current ratings assigned by
S&P and Moody’s, respectively, it could significantly limit our access to
the commercial paper market. Any such downgrade of our long- or
short-term ratings could increase our cost of capital and reduce the
availability of capital and, thus, have a material adverse effect on our
business, financial condition, liquidity and results of
operations. Ratings from credit agencies are not recommendations to
buy, sell or hold our securities. Each rating should be evaluated
independently of any other rating.
A
downgrade in our credit ratings below investment grade would negatively affect
the operations of our Energy Services segment. If our credit ratings fall
below investment grade, ratings triggers and/or adequate assurance clauses in
many of our financial and wholesale physical contracts would be in effect.
A ratings trigger or adequate assurance clause gives a counterparty the right to
suspend or terminate the agreement unless margin thresholds are met. The
additional increase in capital required to support our Energy Services segment
would negatively impact our ability to compete, as well as our ability to
actively manage the risk associated with existing storage and transportation
contracts.
Our
indebtedness could impair our financial condition and our ability to fulfill our
other obligations.
As of
December 31, 2008, we had total indebtedness for borrowed money of approximately
$3.0 billion, which excludes the debt of ONEOK Partners. Our
indebtedness could have significant consequences. For example, it
could:
·
|
make
it more difficult for us to satisfy our obligations with respect to our
notes and our other indebtedness due to the increased debt-service
obligations, which could in turn result in an event of default on such
other indebtedness or our notes;
|
·
|
impair
our ability to obtain additional financing in the future for working
capital, capital expenditures, acquisitions or general business
purposes;
|
·
|
diminish
our ability to withstand a downturn in our business or the
economy;
|
·
|
require
us to dedicate a substantial portion of our cash flow from operations to
debt service payments, reducing the availability of cash for working
capital, capital expenditures, acquisitions, or general
purposes;
|
·
|
limit
our flexibility in planning for, or reacting to, changes in our business
and the industry in which we operate;
and
|
·
|
place
us at a competitive disadvantage compared with our competitors that have
proportionately less debt.
|
We are
not prohibited under the indentures governing our senior notes from incurring
additional indebtedness, but our debt agreements do subject us to certain
operational limitations summarized in the next paragraph. If we incur
significant additional indebtedness, it could worsen the negative consequences
mentioned above and could adversely affect our ability to repay our other
indebtedness.
Our
revolving debt agreements with banks contain provisions that restrict our
ability to finance future operations or capital needs or to expand or pursue our
business activities. For example, certain of these agreements contain
provisions that, among other things, limit our ability to make loans or
investments, make material changes to the nature of our business, merge,
consolidate or engage in asset sales, grant liens, or make negative
pledges. Certain of these agreements also require us to maintain
certain financial ratios, which limits the amount of additional indebtedness we
can incur. 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
are subject to comprehensive energy regulation by governmental agencies, and the
recovery of our costs is dependent on regulatory action.
We are
subject to comprehensive regulation by several federal, state and municipal
utility regulatory agencies, which significantly influences our operating
environment and our ability to recover our costs from utility
customers. The utility regulatory authorities in Oklahoma, Kansas and
Texas regulate many aspects of our utility operations, including customer
service and the rates that we can charge customers. Federal, state
and local agencies also have jurisdiction over many of our other activities,
including regulation by the FERC of our storage and interstate pipeline
assets. The profitability of our regulated operations is dependent on
our ability to pass costs related to providing energy and other commodities
through to our customers. The regulatory environment applicable to
our regulated businesses could impair our ability to recover costs historically
absorbed by our customers.
We are
unable to predict the impact that the future regulatory activities of these
agencies will have on our operating results. Changes in regulations
or the imposition of additional regulations could have an adverse impact on our
business, financial condition and results of operations.
Our
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 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 of these rules, as well as other FERC rules.
Demand
for services of our Distribution and Energy Services segments and for certain of
ONEOK Partners’ products is highly weather sensitive and seasonal.
The
demand for natural gas and for certain of ONEOK Partners’ products, such as
propane, is weather sensitive and seasonal, with a significant portion of
revenues derived from sales to retail marketers for heating during the winter
months. Weather conditions directly influence the volume of, among
other things, natural gas and propane delivered to
customers. Deviations in weather from normal levels and the seasonal
nature of certain of our segments’ business can create large variations in
earnings and short-term cash requirements.
We
are subject to environmental regulations that could be difficult and costly to
comply with.
We are
subject to multiple environmental laws and regulations affecting many aspects of
present and future operations, including air emissions, water quality,
wastewater discharges, solid and hazardous wastes and hazardous material and
substance management. These laws and regulations generally require us
to obtain and comply with a wide variety of environmental registrations,
licenses, permits, inspections and other approvals. Failure to comply
with these laws, regulations, permits and licenses may expose us to fines,
penalties and/or interruptions in our operations that could be material to the
results of operations. If a leak or spill of hazardous substance
occurs from our lines or facilities, in the process of transporting natural gas
or NGLs, or at any facility that we own, operate or otherwise use, we could be
held jointly and severally liable for all resulting liabilities, including
investigation and clean-up costs, which could materially affect our results of
operations and cash flows. In addition, emission controls required
under the federal Clean Air Act and other similar federal and state laws could
require unexpected capital expenditures at our facilities. We cannot
assure that existing environmental regulations will not be revised or that new
regulations will not be adopted or become applicable to us. Revised
or additional regulations that result in increased compliance costs or
additional operating restrictions, particularly if those costs are not fully
recoverable from customers, could have a material adverse effect on our
business, financial condition and results of operations. For further
discussion on this topic, see Note K of the Notes to Consolidated Financial
Statements in this Annual Report on Form 10-K.
We
are subject to risks that could limit our access to capital, thereby increasing
our costs and adversely affecting our results of operations.
We have
grown rapidly in the last several years as a result of
acquisitions. Further acquisitions may require additional external
capital. If we are not able to access capital at competitive rates,
our strategy of enhancing the earnings potential of our existing assets,
including through acquisitions of complementary assets or businesses, will be
adversely affected. A
number of
factors could adversely affect our ability to access capital, including:
(i) general economic conditions; (ii) capital market conditions;
(iii) market prices for natural gas, NGLs and other hydrocarbons;
(iv) the overall health of the energy and related industries; (v) our
ability to maintain our investment-grade credit ratings; and (vi) our
capital structure. Much of our business is capital intensive, and
achievement of our long-term growth targets is dependent, at least in part, upon
our ability to access capital at rates and on terms we determine to be
attractive. If our ability to access capital becomes significantly
constrained, our interest costs will likely increase and our financial condition
and future results of operations could be significantly harmed.
Energy
efficiency and technological advances may affect the demand for natural gas and
adversely affect our operating results.
The
national trend toward increased conservation and technological advances,
including installation of improved insulation and the development of more
efficient furnaces and other heating devices, may decrease the demand for
natural gas by retail customers. More strict conservation measures in
the future or technological advances in heating, conservation, energy generation
or other devices could adversely affect our operations.
The
cost of providing pension and postretirement health care benefits to eligible
employees and qualified retirees is subject to changes in pension fund values
and changing demographics and may increase.
We have a
defined benefit pension plan for certain employees and postretirement welfare
plans that provide postretirement medical and life insurance benefits to certain
employees who retire with at least five years of service. The cost of
providing these benefits to eligible current and former employees is subject to
changes in the market value of our pension and postretirement benefit plan
assets, changing demographics, including longer life expectancy of plan
participants and their beneficiaries and changes in health care
costs.
Any
sustained declines in equity markets and reductions in bond yields may have a
material adverse effect on the value of our pension and postretirement benefit
plan assets. In these circumstances, cash contributions to our
pension plans may be required.
Our
business could be adversely affected by strikes or work stoppages by our
unionized employees.
As of
January 31, 2009, 739 of our 4,742 employees were represented by collective
bargaining units under collective bargaining agreements. We are
involved periodically in discussions with collective bargaining units
representing some of our employees to negotiate or renegotiate labor
agreements. We cannot predict the results of these negotiations,
including whether any failure to reach new agreements will have a negative
effect on our business, financial condition and results of operations or whether
we will be able to reach any agreement with the collective bargaining
units. Any failure to reach agreement on new labor contracts might
result in a work stoppage. Any future work stoppage could, depending
on the operations and the length of the work stoppage, have a material adverse
effect on our business, financial condition and results of certain
operations.
We
may face significant costs to comply with the regulation of greenhouse gas
emissions.
Global
warming is a significant concern for the energy industry. 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. 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 compel 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 emissions
allowances. This type of system 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 and could affect
future results of operations, cash flows or financial condition if such costs
are not recovered through regulated rates.
We
continue to monitor legislative and regulatory developments in this
area. Although we expect 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
do not fully hedge against price changes in commodities. This could
result in decreased revenues and increased costs, thereby resulting in lower
margins and adversely affecting our results of operations.
Certain
of our nonregulated businesses are exposed to market risk and the impact of
market price fluctuations of natural gas, NGLs and crude oil. Market
risk refers to the risk of loss of cash flows and future earnings arising from
adverse changes in commodity energy prices. Our Energy Services
segment’s primary exposures arise from fixed-price physical purchase or sale
agreements that extend for periods of up to five years and natural gas in
storage. Our ONEOK Partners segment’s primary exposures arise from
commodity prices with respect to processing agreements and the differentials
between NGL and natural gas prices with respect to natural gas and NGL
transportation, fractionation and exchange agreements, as well as the
differential between the individual NGL products and the differentials in
natural gas and NGLs in storage utilized in our operations. Our ONEOK
Partners and Energy Services segments are also exposed to the risk of changing
prices or the cost of transportation resulting from purchasing natural gas or
NGLs at one location and selling it at another (referred to as basis
risk). To minimize the risk from market price fluctuations of natural
gas, NGLs and crude oil, we use commodity derivative instruments such as futures
contracts, swaps and options to manage market risk of existing or anticipated
purchases and sales of natural gas, NGLs and crude oil. We adhere to
policies and procedures that monitor our exposure to market risk from open
positions. However, we do not fully hedge against commodity price
changes, and therefore, we retain some exposure to market
risk. Accordingly, any adverse changes to commodity prices could
result in decreased revenue and increased costs.
Our
Distribution segment uses storage to minimize the volatility of natural gas
costs for our customers by storing natural gas in periods of low demand for
consumption in peak demand periods. In addition, various natural gas
supply contracts allow us the option to convert index-based purchases to fixed
prices. Also, we use derivative instruments to hedge the cost of
anticipated natural gas purchases during the winter heating months to protect
customers from upward volatility in the market price of natural
gas.
Federal,
state and local jurisdictions may challenge our tax return
positions.
The
positions taken in our federal and state tax return filings require significant
judgments, use of estimates and the interpretation and application of complex
tax laws. Significant judgment is also required in assessing the
timing and amounts of deductible and taxable items. Despite
management’s belief that our tax return positions are fully supportable, certain
positions may be successfully challenged by federal, state and local
jurisdictions.
Although
we control ONEOK Partners, we may have conflicts of interest with ONEOK Partners
which could subject us to claims that we have breached our fiduciary duty to
ONEOK Partners and its unitholders.
We are
the sole general partner and own 47.7 percent of ONEOK
Partners. Conflicts of interest may arise between us and ONEOK
Partners and its unitholders. In resolving these conflicts, we may
favor our own interests and the interests of our affiliates over the interests
of ONEOK Partners and its unitholders as long as the resolution does not
conflict with the ONEOK Partners’ partnership agreement or our fiduciary duties
to ONEOK Partners and its unitholders.
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 pipeline 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 service territory
could also have an impact on our revenues. Severe weather impacts our
service 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 the 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.
We
may be subject to legislative and regulatory responses to climate change, with
which compliance could be difficult and costly.
Legislative
and regulatory responses related to climate change create financial
risk. Increased public awareness and concern may result in more
state, regional and/or federal requirements to reduce or mitigate the emission
of greenhouse gases. Numerous states have announced or adopted
programs to stabilize and reduce greenhouse gases and federal legislation has
been introduced in both houses of the United States Congress. Our
pipelines, natural gas processing facilities and natural gas liquids
fractionation facilities will potentially be subject to regulation under climate
change policies introduced at either the state or federal level within the next
few years. 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.
RISK
FACTORS RELATED TO ONEOK PARTNERS’ BUSINESS
The
volatility of natural gas, crude oil and NGL prices could adversely affect ONEOK
Partners’ cash flow.
A
significant portion of ONEOK Partners’ revenues are derived from the sale of
commodities received as payment for its natural gas gathering and processing
services, for transportation and storage of natural gas and NGLs, and for the
fractionation of NGLs. As a result, ONEOK Partners is sensitive to
commodity price fluctuations. Commodity prices have been volatile and
are likely to continue to be so in the future. Recent significant and
steep declines in commodity prices and compressions in commodity price
differentials could have material negative impacts on ONEOK Partners’ financial
results. The prices ONEOK Partners receives for its commodities are
subject to wide fluctuations in response to a variety of factors beyond ONEOK
Partners’ control, including the following:
·
|
overall
domestic and global economic
conditions;
|
·
|
relatively
minor changes in the supply of, and demand for, domestic and foreign
energy;
|
·
|
the
availability and cost of transportation
capacity;
|
·
|
the
level of consumer product demand;
|
·
|
geopolitical
conditions impacting supply and demand for natural gas and crude
oil;
|
·
|
domestic
and foreign governmental regulations and
taxes;
|
·
|
the
price and availability of alternative
fuels;
|
·
|
speculation
in the commodity futures markets;
|
·
|
overall
domestic and global economic
conditions;
|
·
|
the
price of natural gas, crude oil, NGL and liquefied natural gas imports;
and
|
·
|
the
effect of worldwide energy conservation
measures.
|
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, ONEOK Partners is paid less
for its commodities, thereby reducing its cash flow. In addition,
production and related volumes could also decline.
ONEOK
Partners’ use of financial instruments to hedge market risk may result in
reduced income.
ONEOK
Partners utilizes financial instruments to mitigate its exposure to interest
rate and commodity price fluctuations. Hedging instruments that are
used to reduce its exposure to interest rate fluctuations could expose it to
risk of financial loss where it has 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 ONEOK Partners would otherwise receive if it has 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 ONEOK Partners’ exposure to commodity price fluctuations may limit the
benefit ONEOK Partners would otherwise receive if market prices for natural gas
and NGLs exceed the stated price in the hedge instrument for these
commodities.
ONEOK
Partners’ inability to execute growth and development projects and acquire new
assets could reduce cash distributions to its unitholders and to
ONEOK.
ONEOK
Partners’ primary business objectives are to generate cash flow sufficient to
pay quarterly cash distributions to unitholders and to increase quarterly cash
distributions over time. ONEOK Partners’ ability to maintain and grow its
distributions to unitholders, including ONEOK, depends on the growth of its
existing businesses and strategic acquisitions. Accordingly, if ONEOK
Partners is unable to implement business development opportunities and finance
such activities on economically acceptable terms, its future growth will be
limited, which could adversely impact its and our results of operations and cash
flows.
Growing
ONEOK Partners’ business by constructing new pipelines and plants or making
modifications to its existing facilities subjects ONEOK Partners 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 ONEOK Partners intends to grow its business is through the construction
of new pipelines and new gathering, processing, storage and fractionation
facilities and through modifications to ONEOK Partners’ existing pipelines and
existing gathering, processing, storage and fractionation
facilities. The construction and modification of pipelines and
gathering, processing, storage and fractionation facilities requires the
expenditure of significant amounts of capital, which may exceed ONEOK Partners’
estimates, and involves numerous regulatory, environmental, political and legal
uncertainties. Construction projects in ONEOK Partners’ industry may
increase demand for labor, materials and rights of way, which, may, in turn,
impact ONEOK Partners’ costs and schedule. If ONEOK Partners
undertakes these projects, it may not be able to complete them on schedule or at
the budgeted cost. Additionally, ONEOK Partners’ revenues may not
increase immediately upon the expenditure of funds on a particular
project. For instance, if ONEOK Partners builds a new pipeline, the
construction will occur over an extended period of time, and ONEOK Partners will
not receive any material increases in revenues until after completion of the
project. ONEOK Partners may have only limited natural gas or NGL
supplies committed to these facilities prior to their
construction. Additionally, ONEOK Partners may construct facilities
to capture anticipated future growth in production in a region in which
anticipated production growth does not materialize. ONEOK Partners
may also rely on estimates of proved reserves in ONEOK Partners’ 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 ONEOK Partners’ expected investment
return, which could adversely affect ONEOK Partners’ results of operations and
financial condition.
ONEOK
Partners does not own all of the land on which its pipelines and facilities are
located, which could disrupt its operations.
ONEOK
Partners does not own all of the land on which certain of its pipelines and
facilities are located, and is, therefore, subject to the risk of increased
costs to maintain necessary land use. ONEOK Partners obtains the
rights to construct and operate certain of its pipelines and related facilities
on land owned by third parties and governmental agencies for a specific period
of time. ONEOK Partners’ loss of these rights, through its inability
to renew right-of-way contracts, or increased costs to renew such rights, could
have a material adverse effect on our financial condition, results of operations
and cash flows.
ONEOK
Partners’ operations are subject to operational hazards and unforeseen
interruptions, which could adversely affect its business and for which ONEOK
Partners may not be adequately insured.
ONEOK
Partners’ 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 pipeline facilities below expected levels of capacity and
efficiency. Other operational hazards and unforeseen interruptions include
adverse weather conditions, accidents, the collision of equipment with ONEOK
Partners’ pipeline facilities (for example, this may occur if a third party were
to perform excavation or construction work near ONEOK Partners’ facilities) and
catastrophic events such as explosions, fires, hurricanes, earthquakes, floods
or other similar events beyond ONEOK Partners’ control. It is also
possible that ONEOK Partners’ 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 ONEOK
Partners’ pipeline caused by such an event could reduce revenues generated by
ONEOK Partners and increase expenses, thereby impairing ONEOK Partners’ ability
to meet its obligations. Insurance proceeds may not be adequate to cover
all liabilities or expenses incurred or revenues lost, and ONEOK Partners is not
fully insured against all risks inherent to ONEOK Partners’ business.
Additionally, in accordance with typical industry practice, ONEOK Partners does
not have any property insurance on any of our underground pipeline systems that
would cover damage to such systems.
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.
For example, change in the insurance markets subsequent to the terrorist
attacks on September 11, 2001 and the hurricanes in 2005 and 2008 have made it
more difficult for ONEOK Partners to obtain certain types of coverage.
Consequently, ONEOK Partners may not be able to renew existing insurance
policies or procure other desirable insurance on commercially reasonable terms,
if at all. If ONEOK Partners was to incur a significant liability for
which ONEOK Partners was not fully insured, it could have a material adverse
effect on ONEOK Partners’ 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 its assets, ONEOK Partners’
volumes and revenue could decline.
ONEOK
Partners’ ability to maintain or expand its businesses depends largely on the
level of drilling and production in the Mid-Continent, Texas, Rocky Mountain and
Gulf Coast regions. Drilling and production are impacted by factors
beyond ONEOK Partners’ control, including:
·
|
demand
for natural gas and refinery-grade crude
oil;
|
·
|
producers’
desire and ability to obtain necessary permits in a timely and economic
manner;
|
·
|
natural
gas field characteristics and production
performance;
|
·
|
surface
access and infrastructure issues;
and
|
·
|
capacity
constraints on natural gas, crude oil and natural gas liquids pipelines
from the producing areas and ONEOK Partners’
facilities.
|
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, ONEOK Partners’ volumes and revenue
could be 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 ONEOK
Partners’ interstate gas transportation services could significantly
decrease.
ONEOK
Partners depends on natural gas supply from the Western Canada Sedimentary Basin
because ONEOK Partners’ interstate pipelines primarily transport 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 ONEOK Partners’ interstate pipelines and production
remains flat or declines, demand for transportation service on ONEOK Partners’
interstate natural gas pipelines could decrease significantly, which could
adversely impact ONEOK Partners’ results of operations.
Pipeline
integrity programs and repairs may impose significant costs and
liabilities.
Pursuant
to a United States Department of Transportation rule, pipeline operators were
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 ONEOK Partners to incur significant capital and operating
expenditures to make repairs or take remediation, preventive or mitigating
actions that are determined to be necessary.
ONEOK
Partners’ regulated pipelines’ transportation rates are subject to review and
possible adjustment by federal and state regulators.
ONEOK
Partners’ regulated pipelines are subject to extensive regulation by the FERC
and state regulatory agencies, which regulate most aspects of ONEOK Partners’
pipeline business, including ONEOK Partners’ 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 ONEOK Partners’
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. ONEOK Partners cannot
assure unitholders that its pipeline systems will be able to recover all of its
costs through existing or future rates.
ONEOK
Partners’ regulated pipeline companies have recorded certain assets that may not
be recoverable from its customers.
Accounting
policies for FERC-regulated companies permit certain assets that result from the
regulated ratemaking process to be recorded on ONEOK Partners balance sheet that
could not be recorded under GAAP for nonregulated entities. ONEOK
Partners considers factors such as regulatory changes and the impact of
competition to determine the probability of future recovery of these
assets. If ONEOK Partners determines future recovery is no longer
probable, ONEOK Partners would be required to write off the regulatory assets at
that time.
ONEOK
Partners’ operations are subject to federal and state laws and regulations
relating to the protection of the environment, which may expose it to
significant costs and liabilities.
The risk
of incurring substantial environmental costs and liabilities is inherent in
ONEOK Partners’ business. ONEOK Partners’ operations are subject to
extensive federal, state and local laws and regulations governing the discharge
of materials into, or otherwise relating to the protection of, the
environment. Examples of these laws include:
·
|
the
federal Clean Air Act and analogous state laws that impose obligations
related to air emissions;
|
·
|
the
federal Clean Water Act and analogous state laws that regulate discharge
of wastewaters from ONEOK Partners’ facilities to state and federal
waters;
|
·
|
the
federal Comprehensive Environmental Response, Compensation and Liability
Act and analogous state laws that regulate the cleanup of hazardous
substances that may have been released at properties currently or
previously owned or operated by ONEOK Partners or locations to which ONEOK
Partners has sent waste for disposal;
and
|
·
|
the
federal Resource Conservation and Recovery Act and analogous state laws
that impose requirements for the handling and discharge of solid and
hazardous waste from ONEOK Partners’
facilities.
|
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
Comprehensive Environmental Response, Compensation and Liability Act, 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 ONEOK
Partners’ business due to its handling of the products it gathers, transports
and processes, air emissions related to its operations, historical industry
operations and waste disposal practices, some of which may be
material. Private parties, including the owners of properties through
which ONEOK Partners’ 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 ONEOK Partners’ operations. Some sites ONEOK Partners
operates 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 ONEOK Partners’ sites. In addition, increasingly
strict laws, regulations and enforcement policies could significantly increase
ONEOK Partners’ 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
on Form 10-K.
ONEOK
Partners’ insurance may not cover all environmental risks and costs or may not
provide sufficient coverage in the event an environmental claim is made against
ONEOK Partners. ONEOK Partners’ business may be 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 adversely affect
ONEOK Partners’ products and activities, and federal and state agencies could
impose additional safety requirements, all of which could materially affect
ONEOK Partners’ profitability.
In
the competition for customers, ONEOK Partners may have significant levels of
uncontracted or discounted transportation and storage capacity on its natural
gas and natural gas liquids pipelines and in its storage assets.
ONEOK
Partners’ natural gas and natural gas liquids pipelines and storage assets
compete with other pipelines and storage facilities for natural gas and NGL
supplies delivered to the markets it serves. As a result of
competition, ONEOK Partners may have significant levels of uncontracted or
discounted capacity on its pipelines and in its storage assets, which could have
a material adverse impact on ONEOK Partners’ results of operations.
ONEOK
Partners is exposed to the credit risk of its customers or counterparties, and
its credit risk management may not be adequate to protect against such
risk.
ONEOK
Partners is subject to the risk of loss resulting from nonpayment and/or
nonperformance by ONEOK Partners’ customers or counterparties. ONEOK
Partners’ 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 ONEOK
Partners for its services. ONEOK Partners assesses the
creditworthiness of its customers or counterparties and obtains security as it
deems appropriate. If ONEOK Partners fails 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 ONEOK Partners’ results
of operations. In addition, if any of ONEOK Partners’ customers or
counterparties files for bankruptcy protection, this could have a material
negative impact on ONEOK Partners’ results of operations.
Any reduction in ONEOK Partners’
credit ratings could materially and adversely affect its business, financial
condition, liquidity and results of operations.
ONEOK
Partners’ 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). However, we cannot provide assurance that any of its
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 ONEOK Partners’ long-term debt rating,
particularly below investment grade, its borrowing costs would increase, which
would adversely affect its financial results, and its potential pool of
investors and funding sources could decrease. Ratings from credit
agencies are not recommendations to buy, sell or hold ONEOK Partners’
securities. Each rating should be evaluated independently of any
other rating.
A
downgrade of ONEOK Partners’ credit rating may require ONEOK Partners to offer
to repurchase certain of its senior notes or may impair its ability to access
capital.
ONEOK
Partners could be required to offer to repurchase certain of its senior notes
due 2010 and 2011 at par value, plus any accrued and unpaid interest, if Moody’s
or S&P rates 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. Further, the indenture governing ONEOK Partners’
senior notes due 2010 and 2011 include an event of default upon acceleration of
other indebtedness of $25 million or more and the indentures governing ONEOK
Partners’ senior notes due 2012, 2016, 2036 and 2037 include 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, 2036 and 2037
to declare those notes immediately due and payable in full. ONEOK
Partners may not have sufficient cash on hand to repurchase and repay any
accelerated senior notes, which may cause ONEOK Partners to borrow money under
its credit facilities or seek alternative financing sources to finance the
repurchases and repayment. ONEOK Partners could also face
difficulties accessing capital or its borrowing costs could increase, impacting
its ability to obtain financing for acquisitions or capital expenditures, to
refinance indebtedness and to fulfill its debt obligations.
ONEOK
Partners has 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 its limited partner units.
When
ONEOK Partners issues additional units or engages in certain other transactions,
ONEOK Partners determines the fair market value of its assets and allocates any
unrealized gain or loss attributable to its assets to the capital accounts of
its unitholders and its general partner. ONEOK Partners’ methodology
may be viewed as understating the value of its 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 ONEOK Partners’ current valuation
methods, subsequent purchasers of common units may have a greater portion of
their Internal Revenue Code Section 743(b) adjustment allocated to ONEOK
Partners’ tangible assets and a lesser portion allocated to ONEOK Partners’
intangible assets. The IRS may challenge ONEOK Partners’ valuation
methods or ONEOK Partners’ allocation of the Section 743(b) adjustment
attributable to ONEOK Partners’ tangible and intangible assets, and allocations
of income, gain, loss and deduction between the general partner and certain of
ONEOK Partners’ unitholders.
A
successful IRS challenge to these methods or allocations could adversely affect
the amount of taxable income or loss being allocated to ONEOK Partners’
unitholders. It also could affect the amount of gain from ONEOK Partners
unitholders’ sale
of common
units and could have a negative impact on the value of the common units or
result in audit adjustments to ONEOK Partners unitholders’ tax returns without
the benefit of additional deductions.
ONEOK
Partners’ treatment of a purchaser of common units as having the same tax
benefits as the seller could be challenged, resulting in a reduction in value of
the common units.
Because
ONEOK Partners cannot match transferors and transferees of common units, ONEOK
Partners is required to maintain the uniformity of the economic and tax
characteristics of these units in the hands of the purchasers and sellers of
these units. ONEOK Partners does so by adopting certain depreciation
conventions that do not conform to all aspects of the United States Treasury
regulations. An IRS challenge to these conventions could adversely affect
the tax benefits to a unitholder of ownership of the common units and could have
a negative impact on their value or result in audit adjustments to ONEOK
Partners unitholders’ tax returns.
Not
applicable.
DESCRIPTION
OF PROPERTIES
ONEOK
Partners
Property - Our ONEOK Partners
segment owns the following assets:
·
|
approximately
10,100 miles and 4,500 miles of natural gas gathering pipelines in the
Mid-Continent and Rocky Mountain regions,
respectively;
|
·
|
nine
active natural gas processing plants with approximately 645 MMcf/d of
processing capacity in the Mid-Continent region and four active natural
gas processing plants with approximately 80 MMcf/d of processing capacity
in the Rocky Mountain region;
|
·
|
approximately
18 MBbl/d of natural gas liquids fractionation capacity at various natural
gas processing plants in the Mid-Continent and Rocky Mountain
regions;
|
·
|
approximately
1,320 miles of FERC-regulated interstate natural gas pipelines with
approximately 2.5 Bcf/d of peak transportation
capacity;
|
·
|
approximately
5,560 miles of intrastate natural gas gathering and state-regulated
intrastate transmission pipelines with peak transportation capacity of
approximately 3.3 Bcf/d;
|
·
|
approximately
51.6 Bcf of total active working natural gas storage
capacity;
|
·
|
approximately
2,011 miles of natural gas liquids gathering pipelines with peak capacity
of approximately 247 MBbl/d;
|
·
|
approximately
163 miles of natural gas liquids distribution pipelines with peak
transportation capacity of approximately 66
MBbl/d;
|
·
|
two
natural gas liquids fractionators with operating capacity of approximately
260 MBbl/d;
|
·
|
150
MBbl/d of fractionation capacity, including leased
capacity;
|
·
|
80
percent ownership interest in one natural gas liquids fractionator with
operating capacity of approximately 160
MBbl/d;
|
·
|
interest
in one natural gas liquids fractionator with proportional operating
capacity of approximately 11
MBbl/d;
|
·
|
one
9 MBbl/d isomerization unit;
|
·
|
six
NGL storage facilities and four other leased facilities in Okalahoma,
Kansas and Texas, with approximately 26.4 MMBbl of total operating
underground NGL storage capacity;
|
·
|
approximately
1,480 miles of FERC-regulated natural gas liquids gathering pipelines with
peak capacity of approximately 203
MBbl/d;
|
·
|
approximately
3,480 miles of FERC-regulated natural gas liquids and refined petroleum
products distribution pipelines with peak transportation capacity of 691
MBbl/d;
|
·
|
eight
NGL product terminals in Missouri, Nebraska, Iowa and Illinois;
and
|
·
|
above-
and below-ground storage facilities in Iowa, Illinois, Nebraska and Kansas
with 978 MBbl operating capacity.
|
ONEOK
Partners’ natural gas pipelines business owns 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 its natural gas storage facilities has been idle since
2001 following natural gas explosions and eruptions of natural gas geysers in
Hutchinson, Kansas. ONEOK Partners began injecting brine into the
idled facility in the first quarter of 2007 in order to ensure its long-term
integrity. ONEOK Partners expects to complete the injection process
by the end of 2011. Monitoring of the facility and review of the data
for the geoengineering study are ongoing, in compliance with a KDHE order while
ONEOK Partners evaluates the alternatives for the facility. Following the
testing of the gathered data, ONEOK Partners expects to return the facility to
storage service, although most likely for a product other than natural
gas. The return to service will require KDHE approval. It is
possible, however, that testing could reveal that it is not safe to return the
facility to service or that the KDHE will not grant the required permits to
resume service.
Utilization - The utilization
rates for ONEOK Partners’ various businesses for 2008 were as
follows:
·
|
natural
gas processing plants were approximately 71
percent;
|
·
|
natural
gas pipelines were approximately 86 percent subscribed, and storage
facilities were fully subscribed;
|
·
|
natural
gas liquids gathering pipelines were approximately 73
percent;
|
·
|
ONEOK
Partners’ average contracted storage volume were approximately 74 percent
of storage capacity;
|
·
|
natural
gas liquids fractionators were approximately 87
percent;
|
·
|
FERC-regulated
natural gas liquids gathering pipelines were approximately 55 percent;
and
|
·
|
natural
gas liquids distribution pipelines were approximately 49
percent.
|
ONEOK
Partners calculated utilization on its assets using a weighted-average approach,
adjusting for the in-service dates of assets placed in service during
2008. The utilization rate of ONEOK Partners’ fractionation
facilities reflects approximate proportional capacity associated with ownership
interests noted above and partial service for the Bushton facilities, which were
placed in service during the second half of 2008.
On
January 1, 2007, the Bushton Plant was temporarily idled as a result of a
decline in natural gas volumes available for natural gas processing at this
straddle plant. Volumes declined due to natural field declines and as
a result of contract terminations, as advances in technology made it more cost
efficient to process natural gas at other facilities. ONEOK Partners
has contracted for all of the capacity of the plant from ONEOK.
During
2007 and 2008, ONEOK Partners 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. Although the Bushton Plant remains idled, ONEOK Partners
currently has 150 MBbl/d of active NGL fractionation capacity as a result of
combining the previously existing fractionation equipment with the new
fractionation facilities. ONEOK Partners resumed fractionating NGLs
at the facilities in the second half of 2008.
Distribution
Property - We own
approximately 18,100 miles of pipeline and other distribution facilities in
Oklahoma, approximately 12,800 miles of pipeline and other distribution
facilities in Kansas, and approximately 9,600 miles of pipeline and other
distribution facilities in Texas.
Energy
Services
Property - Our total natural
gas storage capacity under lease is 91 Bcf, with maximum withdrawal capability
of 2.3 Bcf/d and maximum injection capability of 1.5 Bcf/d. Our
current natural gas transportation capacity is 1.8 Bcf/d. Our
contracted storage and transportation capacity connects major supply and demand
centers throughout the United States and into Canada. Our storage
leases are spread across 25 different contracts and two facilities in
Canada.
Other
Property - We own the 17-story
ONEOK Plaza office building, with approximately 517,000 square feet of net
rentable space, and the associated parking garage. In March 2008,
ONEOK Leasing Company purchased ONEOK Plaza for the total purchase price of
approximately $48 million, which included $17.1 million for the present value of
the remaining lease payments and $30.9 million for the base purchase
price.
Will
Price, et al. v. Gas Pipelines, et al. (f/k/a Quinque Operating Company, et al.
v. Gas Pipelines, et al.), 26th Judicial District, District
Court of Stevens County, Kansas, Civil Department, Case No. 99C30 (“Price I”).
Plaintiffs brought suit on May 28, 1999, against us, five of our
subsidiaries and one of our divisions, as well as approximately 225 other
defendants. Additionally, in connection with the completion of our
acquisition of the natural gas liquids businesses owned by several Koch
companies, on July 1, 2005, we acquired Koch Hydrocarbon, LP (renamed ONEOK
Hydrocarbon, L.P.), which is also one of the defendants in this
case. Plaintiffs sought class certification for its claims for
monetary damages that the defendants had underpaid gas producers and royalty
owners throughout the United States by intentionally understating both the
volume and the heating content of purchased gas. After extensive
briefing and a hearing, the Court refused to certify the class sought by
plaintiffs. Plaintiffs then filed an amended petition limiting the
purported class to gas producers and royalty owners in Kansas, Colorado and
Wyoming and limiting the claim to undermeasurement of volumes. Oral
argument on the plaintiffs’ motion to certify this suit as a class action was
conducted on April 1, 2005. The Court has not yet ruled on the class
certification issue.
Will
Price and Stixon Petroleum, et al. v. Gas Pipelines, et al., 26th Judicial District, District
Court of Stevens County, Kansas, Civil Department, Case No. 03C232 (“Price
II”). This action was filed by the plaintiffs on May 12, 2003,
after the Court had denied class status in Price I. Plaintiffs are
seeking monetary damages based upon a claim that 21 groups of defendants,
including us and four of our subsidiaries, intentionally underpaid gas producers
and royalty owners by understating the heating content of purchased gas in
Kansas, Colorado and Wyoming. Additionally, in connection with the
completion of our acquisition of the natural gas liquids businesses owned by
several Koch companies, on July 1, 2005, we acquired Koch Hydrocarbon, LP
(renamed ONEOK Hydrocarbon, L.P.), which is also one of the defendants in this
case. Price II has been consolidated with Price I for the
determination of whether either or both cases may properly be certified as class
actions. Oral argument on the plaintiffs’ motion to certify this suit
as a class action was conducted on April 1, 2005. The Court has
not yet ruled on the class certification issue.
Mont
Belvieu Emissions, Texas
Commission on Environmental Quality - Personnel of ONEOK Hydrocarbon
Southwest, L.L.C. (OHSL), a subsidiary of ONEOK Partners, are in discussions
with the Texas Commission on Environmental Quality (TCEQ) staff regarding air
emissions from a heat exchanger at ONEOK Partners’ Mont Belvieu fractionator,
which may have exceeded the emissions allowed under its air
permit. OHSL discovered the possibility of excessive air emissions in
May 2008. The TCEQ has not issued a notice of enforcement relating to
the emissions under this permit. Although no assurances can be given,
ONEOK Partners does not believe that any penalties associated with any alleged
violations will have a material adverse effect on its financial position,
results of operations, or net cash flows.
Gas Index
Pricing Litigation: We, ONEOK Energy
Services Company, L.P. (“OESC”) and one other affiliate are defending, either
individually or together, against the following lawsuits that claim damages
resulting from the alleged market manipulation or false reporting of prices to
gas index publications by us and others: Samuel P. Leggett, et al. v. Duke
Energy Corporation, et al. (filed in the Chancery Court for the
Twenty-Fifth Judicial District at Somerville, Tennessee, in January 2005); Sinclair Oil Corporation v. ONEOK
Energy Services Corporation, L.P., et al. (filed in the United States
District Court for the District of Wyoming in September 2005, transferred to
MDL-1566 in the United States District Court for the District of Nevada); J.P. Morgan Trust Company v. ONEOK,
Inc., et al. (filed in the District Court of Wyandotte County, Kansas, in
October 2005, transferred to MDL-1566 in the United States District Court for
the District of Nevada); Learjet, Inc., et al. v. ONEOK,
Inc., et al. (filed in the District Court of Wyandotte, Kansas, in
November 2005, transferred to MDL-1566 in the United States District Court for
the District of Nevada); Breckenridge Brewery of Colorado,
LLC, et al. v. ONEOK, Inc., et al. (filed in the District Court of Denver
County, Colorado, in May 2006, transferred to MDL-1566 in the United States
District Court for the District of Nevada); Missouri Public Service Commission
v. ONEOK, Inc., et al. (filed in the Sixth Judicial Circuit Court of
Jackson County, Missouri, in October 2006); Arandell Corporation, et al. v. Xcel
Energy, Inc., et al. (filed in the Circuit Court for Dane County,
Wisconsin, in December 2006, transferred to MDL-1566 in the United States
District Court for the District of Nevada); Heartland Regional Medical Center,
et al. v. ONEOK, Inc., et al. (filed in the Circuit Court of Buchanan
County, Missouri, transferred to MDL-1566 in the United States District Court
for the District of Nevada). In each of these lawsuits, the
plaintiffs allege that we, OESC and one other affiliate and approximately ten
other energy companies and their affiliates engaged in an illegal scheme to
inflate natural gas prices by providing false information to gas price index
publications during the years from 2000 to 2002. All of the
complaints arise out of the U.S. Commodity Futures Trading Commission
investigation into and reports concerning false gas price index-reporting or
manipulation in the energy marketing industry. Other than as noted
below, each of the cases are in pretrial discovery.
Motions
to dismiss were granted in the Leggett, Sinclair, and Missouri Public Service Commission
cases. The dismissal of the Sinclair case was appealed to
the United States Court of Appeals for the Ninth Circuit, but is in the process
of being remanded back to the multi-district litigation matter MDL-1566 in the
United States District Court for the District of Nevada for further
proceedings. The dismissal of the Leggett case was reversed by
the Tennessee Court of Appeals on October 29, 2008, but the defendants,
including us and OESC, have filed an application with the Tennessee Supreme
Court to appeal the decision. On January 8, 2009, summary judgment
was granted in favor of all of the defendants except one in the Breckenridge case and
judgment was entered against the plaintiffs in favor of those defendants,
including us, OESC and our other affiliate. We continue to analyze
all of these claims and are vigorously defending against them.
ITEM
4.
|
SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS
|
No matter
was submitted to a vote of our security holders, through the solicitation of
proxies or otherwise, during the fourth quarter 2008.
PART
II
ITEM
5.
|
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
|
MARKET
INFORMATION AND HOLDERS
Our
common stock is listed on the NYSE under the trading symbol
“OKE.” The corporate name ONEOK is used in newspaper stock
listings. The following table sets forth the high and low closing
prices of our common stock for the periods indicated.
|
|
Year
Ended
|
|
|
Year
Ended
|
|
|
|
December
31, 2008
|
|
|
December
31, 2007
|
|
|
|
High
|
|
|
Low
|
|
|
High
|
|
|
Low
|
|
First
Quarter
|
|
$ |
49.21 |
|
|
$ |
43.93 |
|
|
$ |
46.13 |
|
|
$ |
40.12 |
|
Second
Quarter
|
|
$ |
50.63 |
|
|
$ |
45.62 |
|
|
$ |
54.58 |
|
|
$ |
44.57 |
|
Third
Quarter
|
|
$ |
49.59 |
|
|
$ |
33.41 |
|
|
$ |
54.86 |
|
|
$ |
43.65 |
|
Fourth
Quarter
|
|
$ |
34.35 |
|
|
$ |
23.17 |
|
|
$ |
52.05 |
|
|
$ |
44.29 |
|
At
February 18, 2009, there were 13,804
holders of record of our 105,239,496
outstanding shares of common stock.
DIVIDENDS
The
following table sets forth the quarterly dividends declared and paid per share
of our common stock during the periods indicated.
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
First
Quarter
|
|
$ |
0.38
|
|
$ |
0.34
|
|
Second
Quarter
|
|
$ |
0.38
|
|
$ |
0.34
|
|
Third
Quarter
|
|
$ |
0.40
|
|
$ |
0.36
|
|
Fourth
Quarter
|
|
$ |
0.40
|
|
$ |
0.36
|
(a)
|
(a)
- Declared in the previous quarter.
|
|
In
January 2009, we declared a dividend of $0.40 per share ($1.60 per share on an
annualized basis) for the fourth quarter of 2008, which was paid on February 13,
2009, to shareholders of record as of January 30, 2009.
ISSUER
PURCHASES OF EQUITY SECURITIES
The
following table sets forth information relating to our purchases of our common
stock for the periods shown.
Period
|
Total
Number of Shares Purchased
|
Average
Price Paid per Share
|
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
|
|
Maximum
Number (or Approximate Dollar Value) of Shares (or Units) that May Be
Purchased Under the Plans or Programs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October
1-31, 2008
|
|
-
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
November
1-30, 2008
|
|
-
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
December
1-31, 2008
|
|
10
|
(1)
|
|
$27.38
|
|
|
|
-
|
|
|
|
-
|
|
|
Total
|
|
10
|
|
|
$27.38
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
- Represents shares repurchased directly from employees, pursuant to our
Employee Stock Award
Program.
|
EMPLOYEE
STOCK AWARD PROGRAM
Under our
Employee Stock Award Program, we issued, for no consideration, to all eligible
employees (all full-time employees and employees on short-term disability) one
share of our common stock when the per-share closing price of our common stock
on the NYSE was for the first time at or above $26 per share, and we have issued
and will continue to issue, for no consideration, one additional share of our
common stock to all eligible employees when the closing price on the NYSE is for
the first time at or above each one dollar increment above $26 per
share. The total number of shares of our common stock available for
issuance under this program is 300,000.
Through
December 31, 2008, a total of 144,352 shares have been issued to employees under
this program. The shares issued under this program have not been
registered under the Securities Act of 1933, as amended (1933 Act), in reliance
upon the position taken by the SEC (see Release No. 6188, dated February 1,
1980) that the issuance of shares to employees pursuant to a program of this
kind does not require registration under the 1933 Act. See Note N of
the Notes to Consolidated Financial Statements in this Annual Report on Form
10-K for additional information.
PERFORMANCE
GRAPH
The
following performance graph compares the performance of our common stock with
the S&P 500 Index and the S&P Utilities Index during the period
beginning on December 31, 2003, and ending on December 31, 2008. The
graph assumes a $100 investment in our common stock and in each of the indices
at the beginning of the period and a reinvestment of dividends paid on such
investments throughout the period.
Value
of $100 Investment Assuming Reinvestment of Dividends
|
At
December 31, 2003, and at the End of Every Year Through December 31,
2008
|
Among
ONEOK, Inc., The S&P 500 Index and The S&P Utilities
Index
|
|
|
Cumulative
Total Return
|
|
|
|
Years
Ending December 31,
|
|
|
|
2003
|
|
|
2004
|
|
|
2005
|
|
|
2006
|
|
|
2007
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ONEOK,
Inc.
|
|
$ |
100.00 |
|
|
$ |
133.74 |
|
|
$ |
130.01 |
|
|
$ |
218.10 |
|
|
$ |
233.19 |
|
|
$ |
157.65 |
|
S&P
500 Index
|
|
$ |
100.00 |
|
|
$ |
110.88 |
|
|
$ |
116.32 |
|
|
$ |
134.69 |
|
|
$ |
142.09 |
|
|
$ |
89.52 |
|
S&P
Utilities Index (a)
|
|
$ |
100.00 |
|
|
$ |
124.28 |
|
|
$ |
145.21 |
|
|
$ |
175.69 |
|
|
$ |
209.73 |
|
|
$ |
148.95 |
|
(a)
- The Standard & Poors Utilities Index is comprised of the following
companies: AES Corp.; Allegheny Energy, Inc.;
|
|
Ameren
Corp.; American Electric Power Co., Inc.; Centerpoint Energy, Inc.; CMS
Energy Corp.; Consolidated Edison, Inc.;
|
|
Constellation
Energy Group, Inc.; Dominion Resources, Inc.; DTE Energy
Co.; Duke Energy Corp.; Dynegy, Inc.; Edison
|
|
International;
Entergy Corp.; Equitable Resources, Inc.; Exelon Corp.; FirstEnergy Corp.;
FPL Group, Inc.; Integrys Energy
|
|
Group,
Inc.; Nicor, Inc.; NiSource, Inc.; Pepco Holdings, Inc.; PG&E Corp.;
Pinnacle West Capital Corp.; PPL Corp.; Progress
|
|
Energy,
Inc.; Public Service Enterprise Group, Inc.; Questar Corp.; SCANA Corp.;
Sempra Energy; Southern Co.; TECO
|
|
Energy,
Inc.; Wisconsin Energy Corp.; and Xcel Energy, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
following table sets forth our selected financial data for each of the periods
indicated.
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(Millions
of dollars, except per share amounts)
|
|
Revenues
|
|
$ |
16,157.4 |
|
|
$ |
13,477.4 |
|
|
$ |
11,920.3 |
|
|
$ |
12,676.2 |
|
|
$ |
5,785.5 |
|
Income
from continuing operations
|
|
$ |
311.9 |
|
|
$ |
304.9 |
|
|
$ |
306.7 |
|
|
$ |
403.1 |
|
|
$ |
224.7 |
|
Net
income
|
|
$ |
311.9 |
|
|
$ |
304.9 |
|
|
$ |
306.3 |
|
|
$ |
546.5 |
|
|
$ |
242.2 |
|
Total
assets
|
|
$ |
13,126.1 |
|
|
$ |
11,062.0 |
|
|
$ |
10,391.1 |
|
|
$ |
9,284.2 |
|
|
$ |
7,199.2 |
|
Long-term
debt, including current maturities
|
|
$ |
4,230.8 |
|
|
$ |
4,635.5 |
|
|
$ |
4,049.0 |
|
|
$ |
2,030.6 |
|
|
$ |
1,884.7 |
|
Basic
earnings per share - continuing operations
|
|
$ |
2.99 |
|
|
$ |
2.84 |
|
|
$ |
2.74 |
|
|
$ |
4.01 |
|
|
$ |
2.21 |
|
Basic
earnings per share - total
|
|
$ |
2.99 |
|
|
$ |
2.84 |
|
|
$ |
2.74 |
|
|
$ |
5.44 |
|
|
$ |
2.38 |
|
Diluted
earnings per share - continuing operations
|
|
$ |
2.95 |
|
|
$ |
2.79 |
|
|
$ |
2.68 |
|
|
$ |
3.73 |
|
|
$ |
2.13 |
|
Diluted
earnings per share - total
|
|
$ |
2.95 |
|
|
$ |
2.79 |
|
|
$ |
2.68 |
|
|
$ |
5.06 |
|
|
$ |
2.30 |
|
Dividends
declared per common share
|
|
$ |
1.56 |
|
|
$ |
1.40 |
|
|
$ |
1.22 |
|
|
$ |
1.09 |
|
|
$ |
0.88 |
|
Financial
data for 2008, 2007 and 2006 is not directly comparable with 2005 and 2004 due
to the significance of the sale of certain assets to ONEOK Partners in April
2006. See discussion of acquisitions and dispositions beginning on
page 36 under “Significant Acquisitions and Divestitures” in Item 7,
Management’s Discussion and Analysis of Financial Condition and Results of
Operation.
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 on Form 10-K.
EXECUTIVE
SUMMARY
The
following discussion highlights some of our achievements this past
year. Please refer to the “Financial Results and Operating
Information,” “Liquidity and Capital Resources,” and “Capital Projects” sections
of Management’s Discussion and Analysis of Financial Condition and Results of
Operation and our consolidated financial statements for additional
information.
Operating Results - Diluted
earnings per share of common stock from continuing operations (EPS) increased to
$2.95 in 2008, compared with $2.79 in 2007. Operating income for 2008
increased to $917.0 million from $822.5 million for 2007. This
increase is primarily due to wider NGL product price differentials, higher
realized commodity prices, increased NGL gathering and fractionation volumes,
and incremental operating income associated with the assets acquired from Kinder
Morgan Energy Partners, L.P. (Kinder Morgan), all in our ONEOK Partners
segment. This increase in operating income was partially offset by
decreases in storage and marketing margins and transportation margins, net of
hedging activities, in our Energy Services segment.
ONEOK Partners’ Equity
Issuance - In March 2008, we purchased from ONEOK Partners, in a private
placement, an additional 5.4 million of ONEOK Partners’ common units for a total
purchase price of approximately $303.2 million. In addition, ONEOK
Partners completed a public offering of 2.5 million common units at $58.10 per
common unit and received net proceeds of $140.4 million after deducting
underwriting discounts but before offering expenses. In conjunction
with ONEOK Partners’ private placement and public offering of common units,
ONEOK Partners GP contributed $9.4 million to ONEOK Partners in order to
maintain its 2 percent general partner interest.
In April
2008, ONEOK Partners sold an additional 128,873 common units at $58.10 per
common unit to the underwriters of the public offering upon the partial exercise
of their option to purchase additional common units to cover
over-allotments. ONEOK Partners received net proceeds of
approximately $7.2 million from the sale of these common units after deducting
underwriting discounts but before offering expenses. In conjunction
with the partial exercise by the underwriters, ONEOK Partners GP contributed
$0.2 million to ONEOK Partners in order to maintain its 2 percent general
partner interest. Following these transactions, our interest in ONEOK
Partners is 47.7 percent.
ONEOK
Partners used a portion of the proceeds from the sale of common units and the
general partner contributions to repay borrowings under its $1.0 billion
revolving credit agreement dated March 30, 2007, as amended July 31, 2007 (the
ONEOK Partners Credit Agreement).
Dividends/Distributions -
During 2008, we paid dividends totaling $1.56 per share, an increase of
approximately 11 percent over the $1.40 per share paid during
2007. We declared a quarterly dividend of $0.40 per share ($1.60 per
share on an annualized basis) in January 2009, an increase of approximately 5
percent over the $0.38 declared in January 2008. During 2008, ONEOK
Partners paid cash distributions totaling $4.205 per unit, an increase of
approximately 6 percent over the $3.98 per unit paid during
2007. ONEOK Partners declared a cash distribution of $1.08 per unit
($4.32 per unit on an annualized basis) in January 2009, an increase of
approximately 5 percent over the $1.025 declared in January 2008.
Capital Projects - ONEOK
Partners placed the following projects in-service during 2008:
·
|
January
- Midwestern Gas Transmission’s eastern extension
pipeline;
|
·
|
July
- final phase of Fort Union Gas Gathering expansion
project;
|
·
|
September
- Woodford Shale natural gas liquids pipeline
extension;
|
·
|
October
- Bushton Fractionation expansion;
|
·
|
November
- Overland Pass Pipeline from Opal, Wyoming to Conway, Kansas;
and
|
·
|
December
- partial operations of the Guardian pipeline extension with interruptible
service from Ixonia, Wisconsin, to Green Bay,
Wisconsin.
|
Key Performance Indicators -
Key performance indicators reviewed by management include:
·
|
return
on invested capital; and
|
·
|
shareholder
appreciation.
|
For 2008,
our basic and diluted earnings per share from continuing operations were $2.99
and $2.95, respectively, representing a 5 percent increase in basic earnings per
share and a 6 percent increase in diluted earnings per share from continuing
operations compared with 2007. For 2007, our basic and diluted
earnings per share from continuing operations were $2.84 and $2.79,
respectively, representing a 4 percent increase in basic earnings per share and
a 4 percent increase in diluted earnings per share from continuing operations
compared with 2006. Return on invested capital was 13 percent in 2008
and 14 percent in 2007 and 2006, respectively.
To
evaluate shareholder appreciation, we compare the total return over a three-year
period of an investment in our stock with the total return of an investment in
the stock of a group of peer companies. For the three-year period
ended December 31, 2008, we ranked fifth in this shareholder appreciation
calculation when compared with 18 of our peers.
Outlook for 2009 - We expect
continued deteriorating economic conditions in 2009, with significant downward
pressures, relative to 2008, on commodity prices for natural gas, NGLs and crude
oil. We anticipate that lower commodity prices will result in reduced
drilling activity, and economic conditions will reduce petrochemical
demand. We also expect continued volatility and disruption in the
financial markets which could result in an increased cost of
capital. We expect depressed commodity prices and tighter capital
markets to also result in the sale or consolidation of underperforming assets in
the industry, which may present opportunities for us.
SIGNIFICANT
ACQUISITIONS AND DIVESTITURES
Acquisition of NGL Pipeline -
In October 2007, ONEOK Partners completed the acquisition of an interstate
natural gas liquids and refined petroleum products pipeline system and related
assets from a subsidiary of Kinder Morgan for approximately $300 million, before
working capital adjustments. The system extends from Bushton and
Conway, Kansas, to Chicago, Illinois, and transports, stores and delivers a full
range of NGL products and refined petroleum products. The
FERC-regulated system spans 1,624 miles and has a capacity to transport up to
134 MBbl/d. The transaction also included approximately 978 MBbl of owned
storage capacity, eight NGL terminals and a 50 percent ownership of
Heartland. ConocoPhillips owns the other 50 percent of Heartland and
is the managing partner of the Heartland joint venture, which consists primarily
of a refined petroleum products terminal and pipelines with access to two other
refined petroleum products terminals. ONEOK Partners’ investment in
Heartland is accounted for under the equity method of
accounting. Financing for this transaction came from a portion of the
proceeds of ONEOK Partners’ September 2007 issuance of $600 million 6.85 percent
Senior Notes due 2037 (the 2037 Notes). See Note I
of the Notes to Consolidated Financial Statements in this Annual
Report on Form 10-K for a discussion of the 2037 Notes. The working
capital settlement was finalized in April 2008, with no material
adjustments.
Overland Pass Pipeline Company
- See “Capital Projects” for discussion of Overland Pass Pipeline
Company.
ONEOK Partners - In April
2006, we sold certain assets comprising our former gathering and processing,
natural gas liquids, and pipelines and storage segments to ONEOK Partners for
approximately $3 billion, including $1.35 billion in cash, before adjustments,
and approximately 36.5 million Class B limited partner units in ONEOK
Partners. The Class B limited partner units and the related general
partner interest contribution were valued at approximately $1.65
billion. We also purchased, through ONEOK Partners GP, from an
affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK
Partners for $40 million. This purchase resulted in our ownership of
the entire 2 percent general partner interest in ONEOK
Partners. Following the completion of the transactions, we owned a
total of approximately 37.0 million common and Class B limited partner units and
the entire 2 percent general partner interest and control of the
partnership. Our overall interest in ONEOK Partners, including the 2
percent general partner interest, was 45.7 percent at the date of
acquisition.
The sale
of certain assets comprising our former gathering and processing, pipelines and
storage, and natural gas liquids segments did not affect our consolidated
operating income on our Consolidated Statements of Income or total assets on our
Consolidated Balance Sheets, as we were already required under EITF 04-5 to
consolidate our investment in ONEOK Partners effective January 1,
2006. However, minority interest expense and net income were
affected. See Note A of the Notes to Consolidated Financial
Statements in this Annual Report on Form 10-K beginning on page 76 for
additional discussion of our consolidation of ONEOK Partners.
Disposition of 20 percent interest in
Northern Border Pipeline - In April 2006, in connection with the
transactions described immediately above, our ONEOK Partners segment completed
the sale of a 20 percent partnership interest in Northern Border Pipeline to TC
PipeLines for approximately $297 million. Our ONEOK Partners segment
recorded a gain on sale of approximately $113.9 million in the second quarter of
2006. ONEOK Partners and TC PipeLines each now own a 50 percent
interest in Northern Border Pipeline, and an affiliate of TransCanada became
operator of the pipeline in April 2007. As a result of this
transaction, ONEOK Partners’ interest in Northern Border Pipeline is accounted
for as an investment under the equity method applied on a retroactive basis to
January 1, 2006.
Acquisition of Guardian Pipeline
Interests - In April 2006, our ONEOK Partners segment acquired the 66-2/3
percent interest in Guardian Pipeline not previously owned by ONEOK Partners for
approximately $77 million, increasing its ownership interest to 100
percent. ONEOK Partners used borrowings from its credit facility to
fund the acquisition of the additional interest in Guardian
Pipeline. Following the completion of the transaction, we
consolidated Guardian Pipeline in our consolidated financial
statements. This change was accounted for on a retroactive basis to
January 1, 2006.
CAPITAL
PROJECTS
All of
the capital projects discussed below are in our ONEOK Partners
segment.
Woodford Shale Natural Gas Liquids
Pipeline Extension - The 78-mile natural gas liquids gathering pipeline
connecting two natural gas processing plants, operated by Devon Energy
Corporation and Antero Resources Corporation, was placed into service in
September 2008. The cost of the project was approximately $36
million, excluding AFUDC. These two plants have the capacity to
produce approximately 25 MBbl/d of unfractionated NGLs. The natural gas
liquids production is gathered by ONEOK Partners’ existing Mid-Continent natural
gas liquids gathering pipelines. Upon completion of the Arbuckle
Pipeline project, the Woodford Shale natural gas liquids production is expected
to be transported through the Arbuckle Pipeline to ONEOK Partners’ Mont Belvieu,
Texas, fractionation facility.
Overland Pass Pipeline Company
- In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a
subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture
called Overland Pass Pipeline Company. In November 2008, Overland
Pass Pipeline Company completed construction of a 760-mile natural gas liquids
pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market
center in Conway, Kansas. The Overland Pass Pipeline is designed to
transport approximately 110 MBbl/d of unfractionated NGLs and can be increased
to approximately 255 MBbl/d with additional pump facilities. During
2006, ONEOK Partners paid $11.6 million to Williams for the acquisition of its
interest in the joint venture and for reimbursement of initial capital
expenditures. A subsidiary of ONEOK Partners owns 99 percent of the
joint venture, managed the construction project, advanced all costs associated
with construction and is currently operating the pipeline. On or
before November 17, 2010, Williams will have the option to increase its
ownership up to 50 percent, with the purchase price determined in accordance
with the joint venture’s operating agreement. If Williams exercises
its option to increase its ownership to the full 50 percent, Williams would have
the option to become operator. The pipeline project cost was
approximately $575 million, excluding AFUDC.
As part
of a long-term agreement, Williams dedicated its NGL production from two of its
natural gas processing plants in Wyoming, estimated to be approximately 60
MBbl/d, to the Overland Pass Pipeline. Subsidiaries of ONEOK Partners
will
provide
downstream fractionation, storage and transportation services to
Williams. ONEOK Partners has also reached agreements with certain
producers for supply commitments of up to an additional 80 MBbl/d and is
negotiating agreements with other producers for supply commitments that could
add an additional 60 MBbl/d of supply to this pipeline within the next three to
five years.
ONEOK
Partners also invested approximately $239 million, excluding AFUDC, to expand
its existing fractionation and storage capabilities and to increase the capacity
of its natural gas liquids distribution pipelines. Part of this
expansion included adding new fractionation facilities at ONEOK Partners’
Bushton location, increasing total fractionation capacity at Bushton to 150
MBbl/d. The addition of the new facilities and the upgrade to the
existing fractionator was completed in October 2008. Additionally,
portions of the natural gas liquids distribution pipeline upgrades were
completed in the second and third quarters of 2008.
Piceance Lateral Pipeline - In
March 2007, ONEOK Partners announced that Overland Pass Pipeline Company also
plans to construct a 150-mile lateral pipeline with capacity to transport as
much as 100 MBbl/d of unfractionated NGLs from the Piceance Basin in Colorado to
the Overland Pass Pipeline. Williams announced that it intends to
construct a new natural gas processing plant in the Piceance Basin and will
dedicate its NGL production from that plant and an existing plant, with
estimated volumes totaling approximately 30 MBbl/d, to be transported by the
lateral pipeline. ONEOK Partners continues to negotiate with other
producers for supply commitments. In October 2008, this project
received approval of various state and federal regulatory authorities allowing
construction to commence. Construction began during the fourth
quarter of 2008 and is expected be completed during the third quarter of
2009. The project is currently estimated to cost in the range of $110
million to $140 million, excluding AFUDC.
D-J Basin Lateral Pipeline -
In September 2008, ONEOK Partners announced plans to construct a 125-mile
natural gas liquids lateral pipeline from the Denver-Julesburg Basin in
northeastern Colorado to the Overland Pass Pipeline, with capacity to transport
as much as 55 MBbl/d of unfractionated NGLs. The project is currently
estimated to cost in the range of $70 million to $80 million, excluding
AFUDC. ONEOK Partners has supply commitments for up to 33 MBbl/d of
unfractionated NGLs with potential for an additional 10 MBbl/d of supply from
new drilling and plant upgrades in the next two years. The pipeline
is currently under construction and is expected to be fully completed during the
first quarter of 2009.
Arbuckle Pipeline Natural Gas Liquids
Pipeline - In March 2007, ONEOK Partners announced plans to build the
440-mile Arbuckle Pipeline, a natural gas liquids pipeline from southern
Oklahoma through northern Texas and continuing on to the Texas Gulf
Coast. The Arbuckle Pipeline will have the capacity to transport 160
MBbl/d of unfractionated NGLs, expandable to 210 MBbl/d with additional pump
facilities, and will connect with ONEOK Partners’ existing Mid-Continent
infrastructure with its fractionation facility in Mont Belvieu, Texas, and other
Gulf Coast region fractionators. ONEOK Partners has supply
commitments from producers that it expects will be sufficient to fill the 210
MBbl/d capacity level over the next three to five years. Construction
on the pipeline has been underway since the third quarter of
2008. Much of the Oklahoma and north Texas portions are either
complete or nearing completion. However, right-of-way acquisition has
been challenging, time consuming and expensive, which could affect the
completion schedule and final cost of the project. Many of Arbuckle
Pipeline’s remaining right-of-way tracts are being acquired through a
condemnation process, which adds to the cost and time to construct the
pipeline. The demand for surface easements has increased dramatically
in Texas and Oklahoma in the last 12 to 18 months because of increased oil and
natural gas exploration and production activities, as well as pipeline
construction. Because of the delays associated with right-of-way
acquisition, we anticipate construction on the south end of the project will be
more difficult and expensive due to wet low-lying areas and potential for spring
rains. Accordingly, we expect the project to be operational in the
second quarter of 2009. Based on the increased costs and delays
associated with right-of-way acquisition and potential weather impacts, our
project costs could increase 10 percent to 15 percent above the range of $340
million to $360 million, excluding AFUDC, as previously reported.
Williston Basin Gas Processing Plant
Expansion - In March 2007, ONEOK Partners announced the expansion of its
Grasslands natural gas processing facility in North Dakota, currently estimated
to cost in the range of $40 million to $45 million, excluding
AFUDC. ONEOK Partners’ estimated project costs increased from $30
million primarily as a result of higher contract labor and equipment
costs. The Grasslands facility is ONEOK Partners’ largest natural gas
processing plant in the Williston Basin. The expansion increases
processing capacity to approximately 100 MMcf/d from its current capacity of 63
MMcf/d and increases fractionation capacity to approximately 12 MBbl/d from 8
MBbl/d. The construction of the expansion project is expected to be
complete in the first quarter of 2009.
Fort Union Gas Gathering
Expansion - In January 2007, Fort Union Gas Gathering announced plans to
double its existing gathering pipeline capacity by adding 148 miles of new
gathering lines, resulting in approximately 649 MMcf/d of additional capacity in
the Powder River basin of Wyoming. The expansion occurred in two
phases and cost approximately $121 million, excluding AFUDC, which was financed
within the Fort Union Gas Gathering partnership. Any cost overruns
are covered through escalation clauses to preserve the original economics of the
project. Phase I, with more than 200 MMcf/d
capacity,
was placed in service during the fourth quarter of 2007. Phase II,
with approximately 450 MMcf/d capacity, was completed in July
2008. The additional capacity has been fully subscribed for 10
years. ONEOK Partners owns approximately 37 percent of Fort Union Gas
Gathering, and accounts for its ownership under the equity method of
accounting.
Guardian Pipeline Expansion and
Extension - In December 2007, Guardian Pipeline received and accepted the
certificate of public convenience and necessity issued by the FERC for its
expansion and extension project. The certificate authorizes ONEOK
Partners to construct, install and operate approximately 119 miles of a 20-inch
and 30-inch natural gas transportation pipeline with a capacity to transport 537
MMcf/d of natural gas north from Ixonia, Wisconsin to the Green Bay, Wisconsin,
area. The project is supported by 15-year shipper commitments with We
Energies and Wisconsin Public Service Corporation and the capacity has been
fully subscribed. The project is currently estimated to cost in the
range of $277 million and $305 million, excluding AFUDC. ONEOK
Partners’ estimated project costs increased from the initial estimate of $241
million in 2006, which excluded AFUDC, primarily due to weather delays,
equipment delivery delays, construction in environmentally sensitive areas,
rocky terrain, and escalating costs associated with crop damage and condemnation
costs. ONEOK Partners received the notice to proceed from the FERC in
May 2008. On December 22, 2008, the FERC issued a letter order
granting Guardian Pipeline’s request for an extension of time for a phased
in-service. On December 29, 2008, the FERC issued a letter order granting
Guardian Pipeline’s request to commence service. On December 31, 2008, the
pipeline and seven meter stations were placed into service with the ability to
transport natural gas on a limited basis. Construction on one compressor
station is complete, and construction on a second compressor station is near
completion. The project is expected to be fully in service in the first
quarter of 2009.
REGULATORY
Several
regulatory initiatives positively impacted the earnings and future earnings
potential for our Distribution segment. See discussion of our
Distribution segment’s regulatory initiative beginning on page 49.
IMPACT
OF NEW ACCOUNTING STANDARDS
Information
about the impact of the following new accounting standards is included in Note A
of the Notes to Consolidated Financial Statements in this Annual Report on Form
10-K:
·
|
Statement
123R, “Share-Based Payment;”
|
·
|
Statement
158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans;”
|
·
|
FIN
48, “Accounting for Uncertainty in Income Taxes - An Interpretation of
FASB Statement No. 109;”
|
·
|
Statement
157, “Fair Value Measurements,” and related FASB Staff Position (FSP)
157-2, “Effective Date of FASB Statement no. 157,” and FSP 157-3,
“Determining the Fair Value of a Financial Asset When the Market for That
Asset Is Not Active;”
|
·
|
Statement
159, “The Fair Value Option for Financial Assets and Financial
Liabilities;”
|
·
|
FSP
FIN 39-1, “Amendment of FASB Interpretation No.
39;”
|
·
|
Statement
141R, “Business Combinations;”
|
·
|
Statement
160, “Noncontrolling Interest in Consolidated Financial Statements - an
amendment to ARB No. 51;”
|
·
|
Statement
161, “Disclosures about Derivative Instruments and Hedging Activities - an
amendment to FASB Statement No.
133;”
|
·
|
EITF
08-6, “Equity Method Investment Accounting Considerations;”
and
|
·
|
Statement
132R-1, “Employers’ Disclosures about Postretirement Benefit Plan
Assets.”
|
CRITICAL
ACCOUNTING 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 estimates most important to the portrayal of our financial
condition and results of operations and requiring 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.
Fair Value Measurements - General - In
September 2006, the FASB issued Statement 157 that establishes a framework for
measuring fair value and requires additional disclosures about fair value
measurements. Beginning January 1, 2008, we partially applied
Statement 157 as allowed by FSP 157-2 that delayed the effective date of
Statement 157 for nonrecurring fair value measurements associated with our
nonfinancial assets and liabilities. As of January 1, 2008, we
applied the provisions of Statement 157 to our recurring fair value
measurements, and the impact was not material upon adoption. As of
January 1, 2009, we have applied the provisions of Statement 157 to our
nonrecurring fair value measurements associated with our nonfinancial assets and
liabilities, and the impact was not material. FSP 157-3, which
clarified the application of Statement 157 in inactive markets, was issued in
October 2008 and was effective for our September 30, 2008, consolidated
financial statements. FSP 157-3 did not have a material impact on our
consolidated financial statements.
In
February 2007, the FASB issued Statement 159 that allows companies to elect to
measure specified financial assets and liabilities, firm commitments, and
nonfinancial warranty and insurance contracts at fair value on a
contract-by-contract basis, with changes in fair value recognized in earnings
each reporting period. At January 1, 2008, we did not elect the fair
value option under Statement 159, and therefore there was no impact on our
consolidated financial statements.
Determining Fair
Value - Statement 157 defines fair value as the price that would be
received to sell an asset or transfer a liability in an orderly transaction
between market participants at the measurement date. We use the
market and income approaches to determine the fair value of our assets and
liabilities and consider the markets in which the transactions are
executed. While many of the contracts in our portfolio are executed
in liquid markets where price transparency exists, some contracts are executed
in markets for which market prices may exist but the market may be relatively
inactive. This results in limited price transparency that requires
management’s judgment and assumptions to estimate fair values. Inputs
into our fair value estimates include commodity exchange prices,
over-the-counter quotes, volatility, historical correlations of pricing data and
LIBOR and other liquid money market instrument rates. We also utilize
internally developed basis curves that incorporate observable and unobservable
market data. We validate our valuation inputs with third-party
information and settlement prices from other sources, where
available. In addition, as prescribed by the income approach, we
compute the fair value of our derivative portfolio by discounting the projected
future cash flows from our derivative assets and liabilities to present
value. The interest rate yields used to calculate the present value
discount factors are derived from LIBOR, Eurodollar futures and Treasury
swaps. The projected cash flows are then multiplied by the
appropriate discount factors to determine the present value or fair value of our
derivative instruments. We also take into consideration the potential
impact on market prices of liquidating positions in an orderly manner over a
reasonable period of time under current market conditions. Finally,
we consider credit risk of our counterparties on the fair value of our
derivative assets, as well as our own credit risk for derivative liabilities,
using default probabilities and recovery rates, net of collateral. We
also take into consideration current market data in our evaluation when
available, such as bond prices and yields and credit default
swaps. Although we use our best estimates to determine the fair value
of the derivative contracts we have executed, the ultimate market prices
realized could differ from our estimates, and the differences could be
material.
Fair Value Hierarchy
- Statement 157 establishes the fair value hierarchy that prioritizes inputs to
valuation techniques based on observable and unobservable data and categorizes
the inputs into three levels, with the highest priority given to Level 1 and the
lowest priority given to Level 3. The levels are described
below.
·
|
Level
1 - Unadjusted quoted prices in active markets for identical assets or
liabilities;
|
·
|
Level
2 - Significant observable pricing inputs other than quoted prices
included within Level 1 that are either directly or indirectly observable
as of the reporting date. Essentially, this represents inputs
that are derived principally from or corroborated by observable market
data; and
|
·
|
Level
3 - Generally unobservable inputs, which are developed based on the best
information available and may include our own internal
data.
|
Determining
the appropriate classification of our fair value measurements within the fair
value hierarchy requires management’s judgment regarding the degree to which
market data is observable or corroborated by observable market data.
Transfers in and out of Level 3 typically result from derivatives for which fair
value is determined based on multiple inputs. If prices change for a
particular input from the previous measurement date to the current measurement
date, the impact could result in the derivative being moved between Level 2 and
Level 3, depending upon management judgment of the significance of the price
change of that particular input to the total fair value of the
derivative.
See Note
C of the Notes to Consolidated Financial Statements in this Annual Report
on Form 10-K for more discussion of fair value measurements.
Derivatives, Accounting for
Financially Settled Transactions and Risk Management Activities - We
engage in wholesale energy marketing, retail marketing, trading and risk
management activities. We account for derivative instruments utilized
in connection with these activities and services in accordance with Statement
133, as amended.
Under
Statement 133, entities are required to record derivative instruments at fair
value, with the exception of normal purchases and normal sales that are expected
to result in physical delivery. See previous discussion in “Fair
Value Measurements” for additional information. Market value changes
result in a change in the fair value of our derivative
instruments. The accounting for changes in the fair value of a
derivative instrument depends on whether it has been designated and qualifies as
part of a hedging relationship and, if so, the nature of the risk being hedged
and how we will determine if the hedging instrument is effective. If
the derivative instrument does not qualify or is not designated as part of a
hedging relationship, then we account for changes in fair value of the
derivative in earnings as they occur. Commodity price volatility may
have a significant impact on the gain or loss in any given
period. For more information on fair value sensitivity and a
discussion of the market risk of pricing changes, see Item 7A, Quantitative and
Qualitative Disclosures about Market Risk.
To reduce
our exposure to fluctuations in natural gas, NGLs and condensate prices, we
periodically enter into futures, forwards, options or swap transactions in order
to hedge anticipated purchases and sales of natural gas, NGLs and condensate and
fuel requirements. Interest-rate swaps are also used to manage
interest-rate risk. Under certain conditions, we designate these
derivative instruments as a hedge of exposure to changes in fair values or cash
flow. For hedges of exposure to changes in cash flow, the effective
portion of the gain or loss on the derivative instrument is reported initially
as a component of accumulated other comprehensive income (loss) and is
subsequently recorded to earnings when the forecasted transaction affects
earnings. Any ineffectiveness of designated hedges is reported in
earnings during the period the ineffectiveness occurs. For hedges of
exposure to changes in fair value, the gain or loss on the derivative instrument
is recognized in earnings during the period of change together with the
offsetting gain or loss on the hedged item attributable to the risk being
hedged.
Upon
election, many of our purchase and sale agreements that otherwise would be
required to follow derivative accounting qualify as normal purchases and normal
sales under Statement 133 and are therefore exempt from fair value accounting
treatment.
The
presentation of settled derivative instruments on either a gross or net basis in
our Consolidated Statements of Income is dependent on a number of factors,
including whether the derivative instrument (i) is held for trading purposes;
(ii) is financially settled; (iii) results in physical delivery or services
rendered; and (iv) qualifies for the normal purchase or sale exception as
defined in Statement 133. In accordance with EITF 03-11, “Reporting
Realized Gains and Losses on Derivative Instruments That Are Subject to FASB
Statement No. 133 and not ‘Held for Trading’ as Defined in EITF Issue No. 02-3,”
EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” and
Statement 133, we report settled derivative instruments as follows:
·
|
all
financially settled derivative contracts are reported on a net
basis;
|
·
|
derivative
instruments considered held for trading purposes that result in physical
delivery are reported on a net
basis;
|
·
|
derivative
instruments not considered held for trading purposes that result in
physical delivery or services rendered are reported on a gross basis;
and
|
·
|
derivatives
that qualify for the normal purchase or sale exception as defined in
Statement 133 are reported on a gross
basis.
|
We apply
the indicators in EITF 99-19 to determine the appropriate accounting treatment
for non-derivative contracts that result in physical delivery.
See Note
D of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K for additional discussion of derivatives and risk management
activities.
Impairment of Long-Lived Assets,
Goodwill and Intangible Assets - We assess our long-lived assets for
impairment based on Statement 144, “Accounting for the Impairment or Disposal of
Long-Lived Assets.” A long-lived asset is tested for impairment
whenever events or changes in circumstances indicate that its carrying amount
may exceed its fair value. Fair values are based on the sum of the
undiscounted future cash flows expected to result from the use and eventual
disposition of the assets.
We assess
our goodwill and indefinite-lived intangible assets for impairment at least
annually based on Statement 142, “Goodwill and Other Intangible
Assets.” There were no impairment charges resulting from our July 1,
2008, impairment test. As a result of recent events in the financial
markets and current economic conditions, we performed a review and determined
that interim testing of goodwill as of December 31, 2008, was not
necessary. As a 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. If the fair value is less than the book value, an
impairment is indicated, and we must perform a second test to measure the amount
of the
impairment. In
the second test, we calculate the implied fair value of the goodwill by
deducting the fair value of all tangible and intangible net assets of the
reporting unit from the fair value determined in step one of the
assessment. If the carrying value of the goodwill exceeds the implied
fair value of the goodwill, we will record an impairment charge.
We use
two generally accepted valuation approaches, an income approach and a market
approach, to estimate the fair value of a reporting unit. Under the
income approach, we use anticipated cash flows over a three-year period plus a
terminal value and discount these amounts to their present value using
appropriate rates of return. Under the market approach, we apply
multiples to forecasted EBITDA amounts. The multiples used are
consistent with historical asset transactions, and the EBITDA amounts are based
on average EBITDA for a reporting unit over a three-year forecasted
period. At December 31, 2008 we had $602.8 million of goodwill
recorded on our Consolidated Balance Sheet as shown below.
|
|
|
|
|
|
|
|
|
|
(Thousands
of dollars) |
ONEOK
Partners
|
|
|
|
$ |
433,537 |
|
|
|
|
Distribution
|
|
|
|
|
157,953 |
|
|
|
|
Energy
Services
|
|
|
|
|
10,255 |
|
|
|
|
Other
|
|
|
|
|
1,099 |
|
|
|
|
Total
goodwill
|
|
|
|
$ |
602,844 |
|
|
|
|
Intangible
assets with a finite useful life are amortized over their estimated useful life,
while intangible assets with an indefinite useful life are not
amortized. All intangible assets are subject to impairment
testing. We had $435.4 million of intangible assets recorded on our
Consolidated Balance Sheet as of December 31, 2008, of which $279.8 million in
our ONEOK Partners segment is being amortized over an aggregate weighted-average
period of 40 years, while the remaining balance has an indefinite
life.
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.
During
2006, we recorded a goodwill and asset impairment related to ONEOK Partners’
Black Mesa Pipeline of $8.4 million and $3.6 million, respectively, which was
recorded as depreciation and amortization. The reduction to our net
income, net of minority interests and income taxes, was $3.0
million.
For the
investments we account for under the equity method, the premium or excess cost
over underlying fair value of net assets is referred to as equity method
goodwill and under Statement 142, is not subject to amortization but rather to
impairment testing pursuant to APB Opinion No. 18, “The Equity Method of
Accounting for Investments in Common Stock.” The impairment test
under APB Opinion No. 18 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
reevaluate the amount at which we carry the excess of cost over fair value of
net assets accounted for under the equity method to determine whether current
events or circumstances warrant adjustments to our carrying value in accordance
with APB Opinion No. 18.
Pension and Postretirement Employee
Benefits - We have defined benefit retirement plans covering certain
full-time employees. We sponsor welfare plans that provide
postretirement medical and life insurance benefits to certain employees who
retire with at least five years of service. Our actuarial consultant
calculates the expense and liability related to these plans and uses statistical
and other factors that attempt to anticipate future events. These
factors include assumptions about the discount rate, expected return on plan
assets, rate of future compensation increases, age and employment
periods. In determining the projected benefit obligations and costs,
assumptions can change from period to period and result in material changes in
the costs and liabilities we recognize. See Note J of the Notes to
Consolidated Financial Statements in this Annual Report on Form 10-K for
additional information.
Assumed
health care cost trend rates have a significant effect on the amounts reported
for our health care plans. A one-percentage point change in assumed
health care cost trend rates would have the following effects.
|
|
One-Percentage
|
|
|
One-Percentage
|
|
|
|
Point
Increase
|
|
|
Point
Decrease
|
|
|
|
(Thousands
of dollars)
|
Effect
on total of service and interest cost
|
|
$ |
1,989 |
|
|
|
$ |
(1,706 |
) |
|
Effect
on postretirement benefit obligation
|
|
$ |
19,585 |
|
|
|
$ |
(17,171 |
) |
|
During
2008, we recorded net periodic benefit costs of $19.8 million related to our
defined benefit pension plans and $28.3 million related to postretirement
benefits. We estimate that in 2009, we will record net periodic
benefit costs of $26.6 million related to our defined benefit pension plans and
$26.1 million related to postretirement benefits. In determining our
estimated expenses for 2009, our actuarial consultant assumed an 8.50 percent
expected return on plan assets and a discount rate of 6.25 percent. A
decrease in our expected return on plan assets to 8.25 percent would increase
our 2009 estimated net periodic benefit costs by approximately $1.9 million for
our defined benefit pension plans and would not have a significant impact on our
postretirement benefit plan. A decrease in our assumed discount rate
to 6.00 percent would increase our 2009 estimated net periodic benefit costs by
approximately $2.4 million for our defined benefit pension plans and $0.6
million for our postretirement benefit plan. For 2009, we anticipate
our total contributions to our defined benefit pension plans and postretirement
benefit plan to be $31.2 million and $11.4 million, respectively, and the
expected benefit payments for our postretirement benefit plan are estimated to
be $16.2 million.
Contingencies - Our accounting
for contingencies covers a variety of business activities, including
contingencies for legal and environmental exposures. We accrue these
contingencies when our assessments indicate that it is probable that a liability
has been incurred or an asset will not be recovered, and an amount can be
reasonably estimated in accordance with Statement 5, “Accounting for
Contingencies.” We base our estimates on currently available facts
and our estimates of the ultimate outcome or resolution. Accruals for
estimated losses from environmental remediation obligations generally are
recognized no later than completion of the remediation feasibility
study. Recoveries of environmental remediation costs from other
parties are recorded as assets when their receipt is deemed
probable. Actual results may differ from our estimates resulting in
an impact, positive or negative, on earnings. See Note K of the Notes
to Consolidated Financial Statements in this Annual Report on Form 10-K for
additional discussion of contingencies.
FINANCIAL
RESULTS AND OPERATING INFORMATION
Consolidated
Operations
Selected Financial Results -
The following table sets forth certain selected financial results for the
periods indicated.
|
|
|
|
|
|
|
|
Variances
|
|
|
Variances
|
|
|
|
Years
Ended December 31,
|
|
2008
vs. 2007
|
|
|
2007
vs. 2006
|
|
Financial
Results
|
|
2008
|
|
2007
|
|
2006
|
|
Increase
(Decrease)
|
|
|
Increase
(Decrease)
|
|
|
|
(Millions
of dollars)
|
|
Revenues
|
|
$ |
16,157.4 |
|
$ |
13,477.4 |
|
$ |
11,920.3 |
|
$ |
2,680.0 |
|
20 |
% |
|
$ |
1,557.1 |
|
13 |
% |
Cost
of sales and fuel
|
|
|
14,221.9 |
|
|
11,667.3 |
|
|
10,198.3 |
|
|
2,554.6 |
|
22 |
% |
|
|
1,469.0 |
|
14 |
% |
Net
margin
|
|
|
1,935.5 |
|
|
1,810.1 |
|
|
1,722.0 |
|
|
125.4 |
|
7 |
% |
|
|
88.1 |
|
5 |
% |
Operating
costs
|
|
|
776.9 |
|
|
761.5 |
|
|
740.8 |
|
|
15.4 |
|
2 |
% |
|
|
20.7 |
|
3 |
% |
Depreciation
and amortization
|
|
|
243.9 |
|
|
228.0 |
|
|
235.5 |
|
|
15.9 |
|
7 |
% |
|
|
(7.5 |
) |
(3 |
%) |
Gain
(loss) on sale of assets
|
|
|
2.3 |
|
|
1.9 |
|
|
116.5 |
|
|
0.4 |
|
21 |
% |
|
|
(114.6 |
) |
(98 |
%) |
Operating
income
|
|
$ |
917.0 |
|
$ |
822.5 |
|
$ |
862.2 |
|
$ |
94.5 |
|
11 |
% |
|
$ |
(39.7 |
) |
(5 |
%) |
Equity
earnings from investments
|
|
$ |
101.4 |
|
$ |
89.9 |
|
$ |
95.9 |
|
$ |
11.5 |
|
13 |
% |
|
$ |
(6.0 |
) |
(6 |
%) |
Allowance
for equity funds used
during
construction
|
|
$ |
50.9 |
|
$ |
12.5 |
|
$ |
2.2 |
|
$ |
38.4 |
|
* |
|
|
$ |
10.3 |
|
* |
|
Other
income (expense)
|
|
$ |
(10.6 |
) |
$ |
14.1 |
|
$ |
1.9 |
|
$ |
(24.7 |
)
|
* |
|
|
$ |
12.2 |
|
* |
|
Interest
expense
|
|
$ |
(264.2 |
) |
$ |
(256.3 |
) |
$ |
(239.7 |
) |
$ |
7.9 |
|
3 |
% |
|
$ |
16.6 |
|
7 |
% |
Minority
interests in income of
consolidated
subsidiaries
|
|
$ |
(288.6 |
) |
$ |
(193.2 |
) |
$ |
(222.0 |
) |
$ |
95.4 |
|
49 |
% |
|
$ |
(28.8 |
) |
(13 |
%) |
Capital
expenditures
|
|
$ |
1,473.1 |
|
$ |
883.7 |
|
$ |
376.3 |
|
$ |
589.4 |
|
67 |
% |
|
$ |
507.4 |
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Percentage change is greater than 100 percent.
|
|
|
|
|
|
|
|
|
|
|
2008 vs. 2007 - Net margin
increased primarily due to wider NGL product price differentials, higher
realized commodity prices, incremental net margin associated with the assets
acquired from Kinder Morgan, and increased NGL gathering and fractionation
volumes, all in our ONEOK Partners segment. Additionally, net margin
increased due to implementation of new rate mechanisms in our Distribution
segment. These increases were partially offset by decreases in
storage and marketing margins and transportation margins, net of hedging
activities, in our Energy Services segment.
Operating
costs increased primarily due to incremental operating expenses associated with
the assets acquired from Kinder Morgan, outside services primarily associated
with scheduled maintenance expenses at ONEOK Partners’ Medford and Mont Belvieu
fractionators, and chemical costs. Operating costs also increased due
to costs associated with the startup of the newly expanded Bushton fractionator
and Overland Pass Pipeline, both in our ONEOK Partners segment.
Depreciation
and amortization increased primarily due to the assets acquired from Kinder
Morgan and depreciation expense associated with ONEOK Partners’ completed
capital projects. Additionally, our Distribution segment had an
increase in depreciation and amortization, primarily due to additional
investment in property, plant and equipment.
Equity
earnings from investments increased primarily due to ONEOK Partners’ share of
the gain on the sale of Bison Pipeline LLC by Northern Border Pipeline and ONEOK
Partners’ earnings related to higher gathering revenues in its natural gas
gathering and processing business’ various investments, partially offset by
reduced throughput on Northern Border Pipeline. ONEOK Partners owns a
50 percent equity interest in Northern Border Pipeline.
Allowance
for equity funds used during construction and capital expenditures increased due
to ONEOK Partners’ capital projects.
Other
income (expense) fluctuated primarily due to investment gains (losses) and
fluctuations in interest income. In addition, other income (expense)
was impacted by realized and unrealized gains on available-for-sale securities
sold and transferred to trading. Our available-for-sale securities
were reclassified to trading securities due to a reconsideration event in August
2008 when our NYMEX Holding, Inc. Class A shares held were converted to CME
Group, Inc. (CME) Class A shares, due to the NYMEX Holding, Inc. and CME
merger. A modification was made to the number of shares required to
be maintained by NYMEX Holding, Inc. Class A Members, which resulted in our sale
of certain shares and the reclassification of the remaining shares to
trading.
Interest
expense increased primarily due to increased borrowings to fund ONEOK Partners’
capital projects.
Minority
interest in income of consolidated subsidiaries for 2008 and 2007 reflects the
remaining 52.3 percent and 54.3 percent, respectively, of ONEOK Partners that we
did not own. The increase in minority interest is due to the increase
in income for our ONEOK Partners segment, partially offset by our increased
equity ownership interest in ONEOK Partners.
2007 vs. 2006 - Net margin
increased primarily due to the implementation of new rate schedules in Kansas
and Texas in our Distribution segment. Net margin was also positively
impacted by our ONEOK Partners segment due to its natural gas liquids
businesses, which benefited primarily from new supply connections that increased
volumes gathered, transported, fractionated and sold. Net margin also
increased due to ONEOK Partners’ natural gas liquids gathering and fractionation
business benefiting from higher product price differentials and higher
isomerization price differentials, as well as the incremental net margin related
to the assets acquired from Kinder Morgan in October 2007. These
increases were offset by decreased transportation margins in our Energy Services
segment and decreased net margin in ONEOK Partners’ natural gas gathering and
processing business, primarily due to lower natural gas volumes processed as a
result of contract terminations in late 2006.
Gain on
sale of assets decreased primarily due to the $113.9 million gain on sale of a
20 percent partnership interest in Northern Border Pipeline recorded in the
second quarter of 2006 in our ONEOK Partners segment.
Equity
earnings from investments decreased primarily due to the decrease in ONEOK
Partners’ share of Northern Border Pipeline’s earnings from 70 percent in the
first quarter of 2006 to 50 percent beginning in the second quarter of
2006.
Allowance
for equity funds used during construction and capital expenditures increased due
to ONEOK Partners’ capital projects.
Other
income (expense) fluctuated primarily due to increased civic donations and
expenses incurred by ONEOK Partners in 2006 related to costs associated with
transitioning operations from Omaha, Nebraska.
Interest
expense increased primarily due to the additional borrowings by ONEOK Partners
to complete the April 2006 transactions with us. The additional
borrowings resulted in $21.3 million in higher interest expense in the first
quarter of 2007. Increased interest expense was partially offset by
lower interest expense on ONEOK’s short-term debt of $11.8 million
during 2007, as a result of the proceeds from the sale of assets to ONEOK
Partners, which reduced ONEOK’s short-term debt.
Minority
interest in income of consolidated subsidiaries for 2007 and 2006 reflects the
remaining 54.3 percent of ONEOK Partners that we did not own. For
2007, minority interest was lower due to the $113.9 million gain on sale of a 20
percent partnership interest in Northern Border Pipeline recorded in the second
quarter of 2006 in our ONEOK Partners segment. Additionally, minority
interest in net income of consolidated subsidiaries for our ONEOK Partners’
segment for 2006 included the 66-2/3 percent interest in Guardian Pipeline that
ONEOK Partners did not own until April 2006. ONEOK Partners owned 100
percent of Guardian Pipeline beginning in April 2006, resulting in no minority
interest in income of consolidated subsidiaries related to Guardian Pipeline
after March 31, 2006.
More
information regarding our results of operations is provided in the following
discussion of operating results for each of our segments.
ONEOK
Partners
Selected Financial Results and
Operating Information - The following tables set forth certain selected
financial results and operating information for our ONEOK Partners segment for
the periods indicated.
|
|
|
|
|
|
|
|
Variances
|
|
|
Variances
|
|
|
Years
Ended December 31,
|
|
2008
vs. 2007
|
|
|
2007
vs. 2006
|
|
Financial
Results
|
|
2008
|
|
2007
|
|
2006
|
|
Increase
(Decrease)
|
|
|
Increase
(Decrease)
|
|
|
(Millions
of dollars)
|
|
Revenues
|
|
$ |
7,720.2 |
|
$ |
5,831.6 |
|
$ |
4,738.2 |
|
$ |
1,888.6 |
|
32 |
% |
|
$ |
1,093.4 |
|
23 |
% |
Cost
of sales and fuel
|
|
|
6,579.5 |
|
|
4,935.7 |
|
|
3,894.7 |
|
|
1,643.8 |
|
33 |
% |
|
|
1,041.0 |
|
27 |
% |
Net
margin
|
|
|
1,140.7 |
|
|
895.9 |
|
|
843.5 |
|
|
244.8 |
|
27 |
% |
|
|
52.4 |
|
6 |
% |
Operating
costs
|
|
|
371.8 |
|
|
337.4 |
|
|
325.8 |
|
|
34.4 |
|
10 |
% |
|
|
11.6 |
|
4 |
% |
Depreciation
and amortization
|
|
|
124.8 |
|
|
113.7 |
|
|
122.0 |
|
|
11.1 |
|
10 |
% |
|
|
(8.3 |
) |
(7 |
%) |
Gain
on sale of assets
|
|
|
0.7 |
|
|
2.0 |
|
|
115.5 |
|
|
(1.3 |
) |
(65 |
%) |
|
|
(113.5 |
) |
(98 |
%) |
Operating
income
|
|
$ |
644.8 |
|
$ |
446.8 |
|
$ |
511.2 |
|
$ |
198.0 |
|
44 |
% |
|
$ |
(64.4 |
) |
(13 |
%) |
Equity
earnings from investments
|
|
$ |
101.4 |
|
$ |
89.9 |
|
$ |
95.9 |
|
$ |
11.5 |
|
13 |
% |
|
$ |
(6.0 |
) |
(6 |
%) |
Allowance
for equity funds used
during
construction
|
|
$ |
50.9 |
|
$ |
12.5 |
|
$ |
2.2 |
|
$ |
38.4 |
|
* |
|
|
$ |
10.3 |
|
* |
|
Minority
interests in income of
consolidated
subsidiaries
|
|
$ |
(0.4 |
) |
$ |
(0.4 |
) |
$ |
(2.4 |
) |
$ |
- |
|
0 |
% |
|
$ |
2.0 |
|
83 |
% |
Capital
expenditures
|
|
$ |
1,253.9 |
|
$ |
709.9 |
|
$ |
201.7 |
|
$ |
544.0 |
|
77 |
% |
|
$ |
508.2 |
|
* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
Percentage change is greater than 100 percent.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years
Ended December 31,
|
|
Operating
Information
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Natural
gas gathered (BBtu/d)
(a)
|
|
|
1,164 |
|
|
|
1,171 |
|
|
|
1,168 |
|
Natural
gas processed (BBtu/d)
(a)
|
|
|
641 |
|
|
|
621 |
|
|
|
988 |
|
Natural
gas transported (MMcf/d)
|
|
|
3,665 |
|
|
|
3,579 |
|
|
|
3,634 |
|
Residue
gas sales (BBtu/d)
(a)
|
|
|
279 |
|
|
|
281 |
|
|
|
302 |
|
NGLs
gathered (MBbl/d)
|
|
|
276 |
|
|
|
248 |
|
|
|
226 |
|
NGL
sales (MBbl/d)
|
|
|
283 |
|
|
|
231 |
|
|
|
207 |
|
NGLs
fractionated (MBbl/d)
|
|
|
373 |
|
|
|
356 |
|
|
|
313 |
|
NGLs
transported (MBbl/d)
|
|
|
333 |
|
|
|
299 |
|
|
|
200 |
|
Conway-to-Mont
Belvieu OPIS average price differential
|
|
|
|
|
|
|
|
|
|
|
|
|
Ethane
($/gallon)
|
|
$ |
0.15 |
|
|
$ |
0.06 |
|
|
$ |
0.05 |
|
Realized
composite NGL sales prices ($/gallon)
(a)
|
|
$ |
1.27 |
|
|
$ |
1.06 |
|
|
$ |
0.93 |
|
Realized
condensate sales price ($/Bbl)
(a)
|
|
$ |
89.30 |
|
|
$ |
67.35 |
|
|
$ |
57.84 |
|
Realized
residue gas sales price ($/MMBtu)
(a)
|
|
$ |
7.34 |
|
|
$ |
6.21 |
|
|
$ |
6.31 |
|
Realized
gross processing spread
($/MMBtu) (a)
|
|
$ |
7.47 |
|
|
$ |
5.21 |
|
|
$ |
5.05 |
|
(a)
- Statistics relate to ONEOK Partners’ natural gas gathering and
processing business.
|
|
2008 vs. 2007 - Net margin
increased primarily due to the following:
·
|
an
increase in ONEOK Partners’ natural gas liquids gathering and
fractionation business due to the
following:
|
o
|
an
increase of $70.8 million in wider NGL product price
differentials;
|
o
|
an
increase of $32.1 million due to increased NGL gathering and fractionation
volumes; and
|
o
|
an
increase of $8.4 million in certain operational measurement gains,
primarily at NGL storage caverns;
|
·
|
an
increase in ONEOK Partners’ natural gas gathering and processing business
due to the following:
|
o
|
an
increase of $58.4 million due to higher realized commodity
prices;
|
o
|
an
increase of $11.9 million due to improved contractual
terms;
|
o
|
an
increase of $7.0 million due to higher volumes sold and processed;
partially offset by
|
o
|
a
decrease of $8.6 million due to a one-time favorable contract settlement
that occurred in the fourth quarter of
2007;
|
·
|
an
increase of $44.3 million in incremental margin in ONEOK Partners’ natural
gas liquids pipelines business, due to the assets acquired from Kinder
Morgan in October 2007, including $10.3 million due to increased
throughput during the fourth quarter of 2008, compared with the fourth
quarter of 2007;
|
·
|
an
increase of $11.7 million due to increased transportation and storage
margins primarily as a result of the impact of higher natural gas prices
on retained fuel, and new and renegotiated storage contracts in ONEOK
Partners’ natural gas pipelines business;
and
|
·
|
an
increase of $6.9 million primarily due to increased throughput from new
NGL supply connections, including $2.6 million from Overland Pass
Pipeline, which began operations during the fourth quarter
2008.
|
Operating
costs increased primarily due to incremental operating expenses associated with
the assets acquired from Kinder Morgan, outside service costs primarily
associated with scheduled maintenance expenses at ONEOK Partners’ Medford and
Mont Belvieu fractionators, and chemical costs. Operating costs also
increased due to costs associated with the startup of ONEOK Partners’ newly
expanded Bushton fractionator and Overland Pass Pipeline.
Depreciation
and amortization increased primarily due to depreciation expense associated with
ONEOK Partners’ completed capital projects and the assets acquired from Kinder
Morgan.
Equity
earnings from investments increased primarily due to higher gathering revenues
in ONEOK Partners’ various investments, as well as a $8.3 million gain on the
sale of Bison Pipeline LLC by Northern Border Pipeline, partially offset by
reduced throughput on Northern Border Pipeline. ONEOK Partners owns a
50 percent equity interest in Northern Border Pipeline.
Allowance
for equity funds used during construction and capital expenditures increased due
to ONEOK Partners’ capital projects.
2007 vs. 2006 - Net margin
increased primarily due to the following:
·
|
an
increase of $27.3 million from increased performance of ONEOK Partners’
natural gas liquids businesses, which benefited primarily from new supply
connections that increased volumes gathered, transported, fractionated and
sold;
|
·
|
an
increase of $20.6 million from new and renegotiated contractual terms and
increased volumes in ONEOK Partners’ natural gas and natural gas liquids
businesses;
|
·
|
an
increase of $13.5 million in higher NGL product price differentials and
higher isomerization price differentials in ONEOK Partners’ natural gas
liquids gathering and fractionation
business;
|
·
|
an
increase of $11.5 million in incremental net margin in ONEOK Partners’
natural gas liquids pipeline business, due to the assets acquired from
Kinder Morgan in October 2007; and
|
·
|
an
increase of $5.4 million in storage margins in ONEOK Partners’ natural gas
pipelines business; partially offset
by
|
·
|
a
decrease of $32.9 million in natural gas processing and transportation
margins in ONEOK Partners’ natural gas businesses resulting primarily from
lower throughput, higher fuel costs and lower volumes processed as a
result of various contract
terminations.
|
Operating
costs increased primarily due to higher employee-related costs and the
incremental operating expenses associated with the assets acquired from Kinder
Morgan, partially offset by lower litigation costs.
Depreciation
and amortization decreased primarily due to a goodwill and asset impairment
charge of $12.0 million recorded in the second quarter of 2006 related to Black
Mesa Pipeline.
Gain on
sale of assets decreased primarily due to the $113.9 million gain on the sale of
a 20 percent partnership interest in Northern Border Pipeline recorded in the
second quarter of 2006.
Equity
earnings from investments primarily include earnings from ONEOK Partners’
interest in Northern Border Pipeline. The decrease for 2007 was
primarily due to the decrease in ONEOK Partners’ share of Northern Border
Pipeline’s earnings from 70 percent in the first quarter of 2006 to 50 percent
beginning in the second quarter of 2006. See page 85 for discussion
of the disposition of the 20 percent partnership interest in Northern Border
Pipeline.
Allowance
for equity funds used during construction and capital expenditures increased due
to ONEOK Partners’ capital projects.
Minority
interest in income of consolidated subsidiaries decreased primarily due to our
acquisition of the remaining interest in Guardian Pipeline. Minority
interest in net income of consolidated subsidiaries for our ONEOK Partners’
segment for 2006 included the 66-2/3 percent interest in Guardian Pipeline that
ONEOK Partners did not own until April 2006. ONEOK Partners owned 100
percent of Guardian Pipeline beginning in April 2006, resulting in no minority
interest in income of consolidated subsidiaries related to Guardian Pipeline
after March 31, 2006.
Commodity Price Risk - ONEOK
Partners is exposed to commodity price risk, primarily from NGLs, as a result of
its contractual obligations for services provided. A small percentage
of its services, based on volume, is provided through keep-whole
arrangements. See discussion regarding ONEOK Partners’ commodity
price risk beginning on page 63 under “Commodity Price Risk” in Item 7A,
Quantitative and Qualitative Disclosures about Market Risk.
Distribution
Selected Financial Results -
The following table sets forth certain selected financial results for our
Distribution segment for the periods indicated.
|
|
|
|
|
|
|
|
Variances
|
|
|
Variances
|
|
|
|
Years
Ended December 31,
|
|
2008
vs. 2007
|
|
|
2007
vs. 2006
|
|
Financial
Results
|
|
2008
|
|
2007
|
|
2006
|
|
Increase
(Decrease)
|
|
|
Increase
(Decrease)
|
|
|
|
(Millions
of dollars)
|
|
Gas
sales
|
|
$ |
2,049.0 |
|
$ |
1,976.3 |
|
$ |
1,836.9 |
|
$ |
72.7 |
|
4 |
% |
|
$ |
139.4 |
|
8 |
% |
Transportation
revenues
|
|
|
87.3 |
|
|
87.3 |
|
|
88.3 |
|
|
- |
|
0 |
% |
|
|
(1.0 |
) |
(1 |
%) |
Cost
of gas
|
|
|
1,496.7 |
|
|
1,435.4 |
|
|
1,358.4 |
|
|
61.3 |
|
4 |
% |
|
|
77.0 |
|
6 |
% |
Net
margin, excluding other
|
|
|
639.6 |
|
|
628.2 |
|
|
566.8 |
|
|
11.4 |
|
2 |
% |
|
|
61.4 |
|
11 |
% |
Other
revenues
|
|
|
41.3 |
|
|
35.4 |
|
|
33.0 |
|
|
5.9 |
|
17 |
% |
|
|
2.4 |
|
7 |
% |
Net
margin
|
|
|
680.9 |
|
|
663.6 |
|
|
599.8 |
|
|
17.3 |
|
3 |
% |
|
|
63.8 |
|
11 |
% |
Operating
costs
|
|
|
375.3 |
|
|
377.8 |
|
|
371.5 |
|
|
(2.5 |
) |
(1 |
%) |
|
|
6.3 |
|
2 |
% |
Depreciation
and amortization
|
|
|
116.8 |
|
|
111.6 |
|
|
110.9 |
|
|
5.2 |
|
5 |
% |
|
|
0.7 |
|
1 |
% |
Gain
(loss) on sale of assets
|
|
|
- |
|
|
(0.1 |
) |
|
- |
|
|
0.1 |
|
100 |
% |
|
|
(0.1 |
) |
(100 |
%) |
Operating
income
|
|
$ |
188.8 |
|
$ |
174.1 |
|
$ |
117.4 |
|
$ |
14.7 |
|
8 |
% |
|
$ |
56.7 |
|
48 |
% |
Capital
expenditures
|
|
$ |
169.0 |
|
$ |
162.0 |
|
$ |
159.0 |
|
$ |
7.0 |
|
4 |
% |
|
$ |
3.0 |
|
2 |
% |
2008 vs. 2007 - Net margin
increased primarily due to:
·
|
an
increase of $15.7 million resulting from the implementation of new rate
mechanisms, which includes a $12.4 million increase in Oklahoma and a $3.3
million increase in Texas; and
|
·
|
an
increase of $2.2 million related to recovery of carrying costs for natural
gas in storage.
|
Operating
costs decreased primarily due to:
·
|
a
decrease of $4.3 million in employee-related costs;
and
|
·
|
a
decrease of $1.0 million in bad debt expense; partially offset
by
|
·
|
an
increase of $2.4 million in fuel-related vehicle
costs.
|
Depreciation
and amortization increased primarily due to:
·
|
an
increase of $4.0 million in depreciation expense related to our investment
in property, plant and equipment;
and
|
·
|
an
increase of $1.2 million of regulatory amortization associated with
revenue rider recoveries.
|
2007 vs. 2006 - Net margin
increased primarily due to:
·
|
an
increase of $55.2 million resulting from the implementation of new rate
schedules, which includes $51.1 million in Kansas and $4.1 million in
Texas; and
|
·
|
an
increase of $8.0 million from higher customer sales volumes as a result of
a return to more normal weather in our entire service
territory.
|
Operating
costs increased primarily due to:
·
|
an
increase of $4.8 million in bad debt expense, primarily in Oklahoma;
and
|
·
|
an
increase of $5.3 million due to higher property taxes in Kansas; partially
offset by
|
·
|
a
decrease of $4.0 million in labor and employee benefit
costs.
|
Capital Expenditures - Our
capital expenditure program includes expenditures for extending service to new
areas, modifying customer service lines, increasing system capabilities, general
replacements and improvements. It is our practice to maintain and
upgrade facilities to ensure safe, reliable and efficient
operations. Our capital expenditure program included $51.8 million,
$50.6 million and $54.9 million for new business development in 2008, 2007 and
2006, respectively.
Selected Operating Information
- The following tables set forth certain selected operating information for our
Distribution segment for the periods indicated.
|
|
Years
Ended December 31,
|
Operating
Information
|
|
2008
|
|
2007
|
|
2006
|
Customers
per employee
|
|
|
719 |
|
|
|
732 |
|
|
|
713 |
|
Inventory
storage balance
(Bcf)
|
|
|
25.1 |
|
|
|
22.7 |
|
|
|
26.3 |
|
|
|
Years
Ended December 31,
|
|
Volumes
(MMcf)
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Gas
sales
|
|
|
|
|
|
|
|
|
|
Residential
|
|
|
125,834 |
|
|
|
121,587 |
|
|
|
110,123 |
|
Commercial
|
|
|
37,758 |
|
|
|
37,295 |
|
|
|
34,865 |
|
Industrial
|
|
|
1,395 |
|
|
|
1,758 |
|
|
|
1,624 |
|
Wholesale
|
|
|
7,186 |
|
|
|
13,231 |
|
|
|
29,263 |
|
Public
Authority
|
|
|
2,592 |
|
|
|
2,679 |
|
|
|
2,520 |
|
Total
volumes sold
|
|
|
174,765 |
|
|
|
176,550 |
|
|
|
178,395 |
|
Transportation
|
|
|
219,398 |
|
|
|
204,049 |
|
|
|
200,828 |
|
Total
volumes delivered
|
|
|
394,163 |
|
|
|
380,599 |
|
|
|
379,223 |
|
|
|
Years
Ended December 31,
|
|
Margin
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Gas
Sales
|
|
(Millions
of dollars)
|
|
Residential
|
|
$ |
444.0 |
|
|
$ |
440.9 |
|
|
$ |
390.2 |
|
Commercial
|
|
|
101.3 |
|
|
|
99.5 |
|
|
|
88.8 |
|
Industrial
|
|
|
2.6 |
|
|
|
2.3 |
|
|
|
2.9 |
|
Wholesale
|
|
|
0.6 |
|
|
|
1.2 |
|
|
|
4.8 |
|
Public
Authority
|
|
|
3.8 |
|
|
|
3.7 |
|
|
|
3.2 |
|
Net
margin on gas sales
|
|
|
552.3 |
|
|
|
547.6 |
|
|
|
489.9 |
|
Transportation
revenues
|
|
|
87.3 |
|
|
|
80.6 |
|
|
|
76.9 |
|
Net
margin, excluding other
|
|
$ |
639.6 |
|
|
$ |
628.2 |
|
|
$ |
566.8 |
|
|
|
Years
Ended December 31,
|
|
Number
of Customers
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Residential
|
|
|
1,886,118 |
|
|
|
1,876,054 |
|
|
|
1,859,480 |
|
Commercial
|
|
|
159,748 |
|
|
|
160,517 |
|
|
|
159,214 |
|
Industrial
|
|
|
1,420 |
|
|
|
1,455 |
|
|
|
1,528 |
|
Wholesale
|
|
|
28 |
|
|
|
27 |
|
|
|
18 |
|
Public
Authority
|
|
|
2,963 |
|
|
|
2,952 |
|
|
|
2,645 |
|
Transportation
|
|
|
10,376 |
|
|
|
9,762 |
|
|
|
8,666 |
|
Total
customers
|
|
|
2,060,653 |
|
|
|
2,050,767 |
|
|
|
2,031,551 |
|
Residential
volumes increased during 2008, compared with 2007, due to colder temperatures in
our Oklahoma and Kansas service territories; however, margins were moderated by
weather normalization mechanisms.
Residential
and commercial volumes increased during 2007, compared with 2006, primarily due
to a return to more normal weather from the unseasonably warm weather in
2006.
Wholesale
sales represent contracted gas volumes that exceed the needs of our residential,
commercial and industrial customer base and are available for sale to other
parties. Wholesale volumes decreased during 2008, compared with 2007
and 2006, due to reduced volumes available for sale.
Public
authority natural gas volumes reflect volumes used by state agencies and school
districts served by Texas Gas Service.
Transportation
margins increased during 2008, compared with 2007, primarily due to increased
transportation volumes in Oklahoma and Kansas.
Regulatory
Initiatives
Oklahoma - In August
2007, Oklahoma Natural Gas filed an application for authorization of a capital
investment recovery mechanism. In February 2008, the OCC approved a
joint stipulation, which allows Oklahoma Natural Gas to collect a rate of
return, depreciation and 50 percent of the property tax expense associated with
non-revenue producing incremental capital investments since its 2005 rate
case. The rates, which were effective in March 2008, generated
margins of approximately $7.7 million in 2008. In July 2008, Oklahoma
Natural Gas filed to increase the capital investment recovery mechanism from
$7.6 million to $12.6 million annually. In October 2008, the parties
signed a joint stipulation approving the request, and an administrative law
judge of the OCC subsequently recommended approval of the joint
stipulation. The final order was approved by the OCC in December
2008, and the increased recovery level was effective in January
2009.
The OCC
has authorized Oklahoma Natural Gas to defer transmission pipeline Integrity
Management Program (IMP) costs incurred (inclusive of operations and maintenance
expense, depreciation, property taxes and a rate of return) in compliance with
the Federal Pipeline Safety Improvement Act of 2002. On January 31,
2007, Oklahoma Natural Gas filed the first application with the OCC seeking
recovery of these costs. On August 31, 2007, the OCC issued an order
approving a stipulation of the parties, which provided for recovery of $7.2
million in IMP deferrals incurred as of July 31, 2007, and these deferrals were
recovered during the months of October 2007 through June 2008.
The
second IMP application was made at the OCC on January 31, 2008, and covered the
IMP deferrals for the months of August through December 2007 and the true-ups
associated with the prior recovery period. This filing also requested
$7.2 million to be recovered with a new IMP billing rate to be put in place in
July 2008. The OCC approved this request, and billings under the 2008
IMP application began in July 2008. The third IMP application was
made at the OCC on January 30, 2009, and covered the IMP deferrals for 2008, and
the true-ups associated with the prior recovery period. This filing
requests a total of $10.8 million with a new IMP billing rate to be put in place
in July 2009. Oklahoma Natural Gas will continue to defer IMP costs
as they are incurred and will make future filings to recover those
costs.
In August
2008, Oklahoma Natural Gas filed with the OCC for approval to include the
fuel-related portion of bad debts in the Purchased Gas Adjustment mechanism
for cost recovery. In October 2008, all parties signed the joint
stipulation approving the request, and an administrative law judge of the OCC
subsequently recommended approval of the joint stipulation. The joint
stipulation allows Oklahoma Natural Gas to begin deferring its fuel-related bad
debts beginning in January 2009 and to collect those amounts above the levels in
base rates through the Purchased Gas Adjustment beginning in January
2010. The final order was issued by the OCC in December
2008. The associated deferrals began in January 2009.
In
October 2008, a joint application for incentive-based rates was filed by the OCC
staff and Oklahoma Natural Gas. This application proposes that the OCC
adopt an incentive-based rate design and more streamlined regulatory
process. If approved, this will provide for more timely rate
changes.
Kansas - In October
2006, Kansas Gas Service reached a settlement with the KCC staff and all other
parties to increase annual revenues by approximately $52 million. The
terms of the settlement were approved by the KCC in November
2006. The rate increase is effective for services rendered on or
after January 1, 2007.
In August
2008, Kansas Gas Service filed an application with the KCC to impose a surcharge
designed to annually collect approximately $2.9 million in costs associated with
its Gas System Reliability Surcharge (GSRS) mechanism. The GSRS mechanism
allows natural gas utilities to earn a return and recover carrying costs
associated with investments made to comply with state and federal pipeline
safety requirements or costs to relocate existing facilities pursuant to
requests made by a government entity. The KCC approved the request in
December 2008, with authorized GSRS collections effective with customer billings
on January 1, 2009.
Texas - Texas Gas
Service has received several regulatory approvals to implement rate increases in
various municipalities in Texas. A total of $1.7 million in annual
rate increases were approved and implemented in 2007. A total of $5.5
million in annual rate increases were approved and implemented in
2006.
In August
2007, Texas Gas Service filed for a rate adjustment with the city of El Paso,
Texas, and the municipalities of Anthony, Clint, Horizon City, Socorro and
Vinton. Texas Gas Service requested a total annual increase of $5.5
million. In February 2008, the El Paso City Council approved an
annual rate increase of approximately $3.1 million. The increase was
effective in February 2008.
In April
2008, the RRC approved a rate increase in our South Texas
jurisdiction. The rate increase was effective May 2008 and will
increase revenues by $1.1 million annually.
In May
2008, Texas Gas Service filed for interim rate relief under the Gas Reliability
Infrastructure Program with the city of El Paso, Texas, and surrounding
communities for approximately $1.1 million. This program is a capital
recovery mechanism that allows for an interim rate adjustment providing recovery
and a return on incremental capital investments made between rate
cases. In August 2008, an annual rate increase of approximately $1.0
million was approved; the new rates were effective in September
2008.
In
February 2009, Texas Gas Service filed a statement of intent to increase rates
in its central Texas service area for approximately $3.6 million. If
approved, new rates are expected to become effective in June 2009.
General - Certain costs to be
recovered through the ratemaking process have been recorded as regulatory assets
in accordance with Statement 71, “Accounting for the Effects of Certain Types of
Regulation.” Should recovery cease due to regulatory actions, certain
of these assets may no longer meet the criteria of Statement 71, and
accordingly, a write-off of regulatory assets and stranded costs may be
required.
Energy
Services
Selected Financial Results -
The following table sets forth certain selected financial results for our Energy
Services segment for the periods indicated.
|
|
|
|
|
|
|
|
Variances
|
|
|
Variances
|
|
|
|
Years
Ended December 31,
|
|
2008
vs. 2007
|
|
|
2007
vs. 2006
|
|
Financial
Results
|
|
2008
|
|
2007
|
|
2006
|
|
Increase
(Decrease)
|
|
|
Increase
(Decrease)
|
|
|
|
(Millions
of dollars)
|
|
Revenues
|
|
$ |
7,585.8 |
|
$ |
6,629.4 |
|
$ |
6,335.8 |
|
$ |
956.4 |
|
14 |
% |
|
$ |
293.6 |
|
5 |
% |
Cost
of sales and fuel
|
|
|
7,475.1 |
|
|
6,382.0 |
|
|
6,062.0 |
|
|
1,093.1 |
|
17 |
% |
|
|
320.0 |
|
5 |
% |
Net
margin
|
|
|
110.7 |
|
|
247.4 |
|
|
273.8 |
|
|
(136.7 |
) |
(55 |
%) |
|
|
(26.4 |
) |
(10 |
%) |
Operating
costs
|
|
|
35.6 |
|
|
39.9 |
|
|
42.5 |
|
|
(4.3 |
) |
(11 |
%) |
|
|
(2.6 |
) |
(6 |
%) |
Depreciation
and amortization
|
|
|
0.9 |
|
|
2.1 |
|
|
2.1 |
|
|
(1.2 |
) |
(57 |
%) |
|
|
- |
|
0 |
% |
Gain
on sale of assets
|
|
|
1.5 |
|
|
- |
|
|
- |
|
|
1.5 |
|
100 |
% |
|
|
- |
|
0 |
% |
Operating
income
|
|
$ |
75.7 |
|
$ |
205.4 |
|
$ |
229.2 |
|
$ |
(129.7 |
) |
(63 |
%) |
|
$ |
(23.8 |
) |
(10 |
%) |
Capital
expenditures
|
|
$ |
0.1 |
|
$ |
0.2 |
|
$ |
- |
|
$ |
(0.1 |
) |
(50 |
%) |
|
$ |
0.2 |
|
100 |
% |
Energy
markets were affected by higher commodity prices during 2008, compared with
2007. The increase in commodity prices had a direct impact on our revenues
and the cost of sales and fuel.
2008 vs. 2007 - Net margin
decreased primarily due to the following:
·
|
a
net decrease of $40.3 million in transportation margins, net of hedging
activities, primarily due to decreased basis differentials between the
Rocky Mountain and Mid-Continent regions, and increased
transportation-related costs in
2008;
|
·
|
a
decrease of $13.9 million in financial trading margins;
and
|
·
|
a
net decrease of $83.3 million in storage and marketing margins, net of
hedging activities, primarily due
to:
|
o
|
a
net decrease of $87.3 million in physical storage margins net of hedging
activities, as a result of:
|
·
|
hedging
opportunities associated with weather related events that led to higher
storage margins in 2007 compared with
2008;
|
·
|
lower
2008 storage margins related to storage risk management positions and the
impact of changes in natural gas prices on these positions;
and
|
·
|
fewer
opportunities to optimize storage capacity due to the significant decline
in natural gas prices in the second half of
2008;
|
o
|
a decrease
of $9.7 million in physical storage margins due to a lower of cost or
market write-down on natural gas inventory;
and
|
o
|
a
decrease of $2.1 million due to colder than anticipated weather and market
conditions that increased the supply cost of managing our peaking and
load-following services and provided fewer opportunities to increase
margins through optimization activities, primarily in the first quarter of
2008; partially offset by
|
o
|
an
increase of $15.8 million from changes in the unrealized fair value of
derivative instruments associated with storage and marketing activities
and improved marketing margins, which benefited from price movements and
optimization activities.
|
Operating
costs decreased primarily due to lower employee-related costs and depreciation
expense.
2007 vs. 2006 - Net margin
decreased primarily due to:
·
|
a
decrease of $22.0 million in transportation margins, net of hedging
activities, associated with changes in the unrealized fair value of
derivative instruments and the impact of a force majeure event on the
Cheyenne Plains Gas Pipeline, as more fully described
below;
|
·
|
a
decrease of $5.0 million in retail activities from lower physical margins
due to market conditions and increased
competition;
|
·
|
a
decrease of $4.3 million in financial trading margins that was partially
offset by
|
·
|
an
increase of $4.9 million in storage and marketing margins, net of hedging
activities, related to:
|
o
|
an
increase in physical storage margins, net of hedging activity, due to
higher realized seasonal storage spreads and optimization activities;
partially offset by
|
o
|
a
decrease in marketing margins; and
|
o
|
a
net increase in the cost associated with managing our peaking and load
following services, slightly offset by higher demand fees collected for
these services.
|
In
September 2007, a portion of the volume contracted under our firm transportation
agreement with Cheyenne Plains Gas Pipeline Company was curtailed due to a fire
at a Cheyenne Plains pipeline compressor station. The fire damaged a
significant amount of instrumentation and electrical wiring, causing Cheyenne
Plains Gas Pipeline Company to declare a force majeure event on the
pipeline. This firm commitment was hedged in accordance with
Statement 133. The discontinuance of fair value hedge accounting on
the portion of the firm commitment that was impacted by the force majeure event
resulted in a loss of approximately $5.5 million that was recognized in the
third quarter of 2007, of which $2.4 million of insurance proceeds were
recovered and recognized in the first quarter of 2008. Cheyenne
Plains Gas Pipeline Company resumed full operations in November
2007.
Operating
costs decreased primarily due to decreased legal and employee-related costs, and
reduced ad-valorem tax expense.
Selected Operating Information
- The following table sets forth certain selected operating information for our
Energy Services segment for the periods indicated.
|
|
Years
Ended December 31,
|
|
Operating
Information
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Natural
gas marketed (Bcf)
|
|
|
1,160 |
|
|
|
1,191 |
|
|
|
1,132 |
|
Natural
gas gross margin ($/Mcf)
|
|
$ |
0.07 |
|
|
$ |
0.19 |
|
|
$ |
0.22 |
|
Physically
settled volumes (Bcf)
|
|
|
2,359 |
|
|
|
2,370 |
|
|
|
2,288 |
|
Our
natural gas in storage at December 31, 2008, was 81.9 Bcf, compared with 66.7
Bcf at December 31, 2007. At December 31, 2008, our total natural gas
storage capacity under lease was 91 Bcf, compared with 96 Bcf at December 31,
2007.
Natural
gas volumes marketed decreased slightly during 2008, compared with 2007, due to
increased injections in the third quarter of 2008. In addition,
demand for natural gas was impacted by weather-related events in the third
quarter of 2008, including a 15 percent decrease in cooling degree-days and
demand disruption caused by Hurricane Ike.
Natural
gas volumes marketed increased during 2007, compared with 2006, due to an
increase in sales activity in the southeastern United States in the third
quarter of 2007. Natural gas volumes were also impacted by a 14
percent increase in heating degree-days in our service territory, compared with
the same period in 2006.
The
acquisition of natural gas storage capacity is more competitive as a result of
new market entrants. The increased demand for storage capacity has
resulted in an increase in both the cost of leasing storage capacity and the
required term of the lease. Longer terms and increased costs for
storage capacity leases could result in significant increases in the cost of our
contractual commitments.
The
following table shows our margins by activity for the periods
indicated.
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
(Millions
of dollars)
|
|
Marketing,
storage and transportation, gross
|
|
$ |
313.4 |
|
|
$ |
409.1 |
|
|
$ |
414.9 |
|
Less: Storage
and transportation costs
|
|
|
(219.8 |
) |
|
|
(191.9 |
) |
|
|
(180.7 |
) |
Marketing,
storage and transportation, net
|
|
|
93.6 |
|
|
|
217.2 |
|
|
|
234.2 |
|
Retail
marketing
|
|
|
14.8 |
|
|
|
14.0 |
|
|
|
19.0 |
|
Financial
trading
|
|
|
2.3 |
|
|
|
16.2 |
|
|
|
20.6 |
|
Net
margin
|
|
$ |
110.7 |
|
|
$ |
247.4 |
|
|
$ |
273.8 |
|
Marketing,
storage and transportation, net, primarily includes physical marketing,
purchases and sales, firm storage and transportation capacity expense, including
the impact of cash flow and fair value hedges, and other derivative instruments
used to manage our risk associated with these activities. Risk
management and operational decisions have a significant impact on the net result
of our marketing and storage activities. Origination gains are also a
component of marketing activity, which is the fair value recognition of
contracts that our wholesale marketing department structures to meet the risk
management needs of our customers.
Retail
marketing includes revenues from providing physical marketing and supply
services, coupled with risk management services, to residential, municipal, and
small commercial and industrial customers.
Financial
trading margin includes activities that are generally executed using financially
settled derivatives. These activities are normally short term in
nature, with a focus on capturing short-term price
volatility. Revenues in our Consolidated Statements of Income include
financial trading margins, as well as certain physical natural gas transactions
with our trading counterparties. Revenues and cost of sales and fuel
from such physical transactions are required to be reported on a net
basis.
Contingencies
Legal Proceedings - We are a
party to various litigation matters and claims that are normal in the course of
our operations. While the results of litigation and claims cannot be
predicted with certainty, we believe the final outcome of such matters will not
have a material adverse effect on our consolidated results of operations,
financial position or liquidity.
FERC Matter - As a result of a
transaction that was brought to the attention of one of our affiliates by a
third party, we conducted an internal review of transactions that may have
violated FERC natural gas capacity release rules or related rules and determined
that there were transactions that should be disclosed to the FERC. We
notified the FERC of this review and filed a report with the FERC regarding
these transactions in March 2008. We cooperated fully with the FERC
in its investigation of this matter and have taken steps to better ensure that
current and future transactions comply with applicable FERC regulations by
implementing a compliance plan dealing with capacity release. We
entered into a global settlement with the FERC to resolve this matter and other
FERC enforcement matters, which was approved by the FERC on January 15,
2009. The global settlement provides for a total civil penalty of
$4.5 million and approximately $2.2 million in disgorgement of profits and
interest, of which $1.7 million of the civil penalty was allocated to ONEOK
Partners. The amounts were recorded as a liability on our
Consolidated Balance Sheet as of December 31, 2008. We made the
required payments in January 2009.
LIQUIDITY
AND CAPITAL RESOURCES
General - Part of our strategy
is to grow through acquisitions and internally generated growth projects that
strengthen and complement our existing assets. We have relied
primarily on operating cash flow, borrowings from commercial paper and credit
agreements, and issuance of debt and equity in the capital markets for our
liquidity and capital resource requirements. We expect to continue to
use these sources for liquidity and capital resource needs on both a short- and
long-term basis. We have no material guarantees of debt or other
similar commitments to unaffiliated parties.
During
2008 and continuing into 2009, the capital markets experienced volatility and
disruption, which could limit our access to those markets or increase the cost
of issuing new securities in the future. Higher commodity prices and wider
basis differentials, particularly in 2008, have also resulted in higher
collateral requirements and natural gas inventory costs in our Energy Services
segment. Throughout this period, ONEOK has continued to have access
to its $1.2 billion revolving credit agreement (ONEOK Credit Agreement); also,
ONEOK Partners has continued to have access to the ONEOK Partners Credit
Agreement, which has been adequate to fund short-term liquidity
needs. In addition, beginning in August 2008, ONEOK had access to its
new short-term credit agreement. In the third quarter of 2008, ONEOK
began to utilize both of its credit agreements and lessened its use of
commercial paper due to decreased liquidity and rising costs in the commercial
paper market. See discussion below under “Short-term
Liquidity.” Also in 2008, ONEOK Partners issued common units and
received additional contributions from ONEOK Partners GP. See
discussion below under “Long-term Financing.”
We expect
continued deteriorating economic conditions in 2009, with downward pressures,
relative to 2008, on commodity prices. We also expect continued
volatility and disruption in the financial markets, which could result in an
increased cost of capital. ONEOK and ONEOK Partners’ ability to
continue to access capital markets for debt and equity financing under
reasonable terms depends on the Company’s and Partnership’s respective financial
condition, credit ratings and market conditions. ONEOK and ONEOK
Partners anticipate that cash flow generated from operations, existing capital
resources and ability to obtain financing will enable both to maintain current
levels of operations and planned operations, collateral requirements and capital
expenditures.
Capitalization Structure - The
following table sets forth our capitalization structure for the periods
indicated.
|
Years
Ended December 31,
|
|
|
2008
|
|
2007
|
|
Long-term
debt
|
|
67%
|
|
70%
|
|
Equity
|
|
33%
|
|
30%
|
|
|
|
|
|
|
|
Debt
(including notes payable)
|
|
76%
|
|
71%
|
|
Equity
|
|
24%
|
|
29%
|
|
ONEOK
does not guarantee the debt of ONEOK Partners. For purposes of determining
compliance with financial covenants in the ONEOK Credit Agreement and ONEOK’s
$400 million 364-day revolving credit facility dated August 6, 2008 (the 364-Day
Facility), the debt of ONEOK Partners is excluded. At December 31,
2008, ONEOK’s capitalization structure, excluding the debt of ONEOK Partners,
was 44 percent long-term debt and 56 percent equity, compared with 51 percent
long-term debt and 49 percent equity at December 31, 2007. At
December 31, 2008, ONEOK’s capitalization structure, including notes payable and
excluding the debt of ONEOK Partners, was 59 percent debt and 41 percent equity,
compared with 52 percent debt and 48 percent equity at December 31,
2007. In February 2008, ONEOK repaid $402.3 million of maturing
long-term debt with cash from operations and short-term
borrowings. In February 2009, ONEOK repaid $100 million of maturing
long-term debt with cash from operations and short-term borrowings.
Cash Management - ONEOK and
ONEOK Partners each use similar centralized cash management programs that
concentrate the cash assets of their operating subsidiaries in joint accounts
for the purpose of providing financial flexibility and lowering the cost of
borrowing, transaction costs and bank fees. Both centralized cash
management programs provide that funds in excess of the daily needs of the
operating subsidiaries are concentrated, consolidated or otherwise made
available for use by other entities within the respective consolidated
groups. ONEOK Partners’ operating subsidiaries participate in these
programs to the extent they are permitted under FERC
regulations. Under these cash management programs, depending on
whether a participating subsidiary has short-term cash surpluses or cash
requirements, ONEOK and ONEOK Partners provide cash to their subsidiary or the
subsidiary provides cash to them.
Short-term Liquidity - ONEOK’s
principal sources of short-term liquidity consist of cash generated from
operating activities, quarterly distributions from ONEOK Partners, the ONEOK
Credit Agreement and the 364-Day Facility, as discussed below. ONEOK
also has a commercial paper program that can be utilized for short-term
liquidity needs, to the extent funds are available under the ONEOK Credit
Agreement and the 364-Day Facility. ONEOK Partners’ principal sources
of short-term liquidity consist of cash generated from operating activities and
the ONEOK Partners Credit Agreement.
During
late 2008, ONEOK and ONEOK Partners decided to borrow under their available
credit facilities to fund their respective anticipated working capital
requirements for the remainder of 2008 and into 2009.
In August
2008, ONEOK entered into the 364-Day Facility. The interest rate is
based, at ONEOK’s election, on either (i) the higher of prime or one-half of one
percent above the Federal Funds Rate or (ii) the Eurodollar rate plus a set
number of basis points based on ONEOK’s current long-term unsecured debt ratings
by Moody’s and S&P. The 364-Day Facility is being used for
working capital, capital expenditures and other general corporate
purposes.
In
September 2008, ONEOK entered into an amendment to the ONEOK Credit
Agreement. The amendment changed certain sublimits but did not change the
lenders’ aggregate commitment to lend up to $1.2 billion under the ONEOK Credit
Agreement.
The total
amount of short-term borrowings authorized by ONEOK’s Board of Directors is $2.5
billion. At December 31, 2008, ONEOK had no commercial paper
outstanding, $1.4 billion in borrowings outstanding, $64.9 million in letters of
credit issued, which includes $64.6 million under the ONEOK Credit Agreement and
an additional $0.3 million in other letters of credit, and available cash and
cash equivalents of approximately $332.4 million. Considering
outstanding borrowings, commercial paper and letters of credit under the ONEOK
Credit Agreement, ONEOK had $135.4 million of credit available at December 31,
2008, under the ONEOK Credit Agreement and the 364-Day Facility. As
of December 31, 2008, ONEOK could have issued $1.5 billion of additional short-
and long-term debt under the most restrictive provisions contained in its
various borrowing agreements.
The total
amount of short-term borrowings authorized by the Board of Directors of ONEOK
Partners GP, the general partner of ONEOK Partners, is $1.5
billion. At December 31, 2008, ONEOK Partners had $870 million in
borrowings outstanding and $130 million of credit available under the ONEOK
Partners Credit Agreement and available cash and cash equivalents of
approximately $177.6 million. As of December 31, 2008, ONEOK Partners
could have issued a $772.6 million of additional short- and long-term debt under
the most restrictive provisions of its agreements.
ONEOK
Partners has an outstanding $25 million letter of credit issued by Royal Bank of
Canada, which is used for counterparty credit support.
ONEOK
Partners also has a $15 million Senior Unsecured Letter of Credit Facility and
Reimbursement Agreement with Wells Fargo Bank, N.A., of which $12 million is
currently being used, and an agreement with Royal Bank of Canada, pursuant to
which a $12 million letter of credit was issued. Both agreements are
used to support various permits required by the KDHE for ONEOK Partners’ ongoing
business in Kansas.
The ONEOK
Credit Agreement and the 364-Day Facility contain certain financial, operational
and legal covenants. These requirements include, among
others:
·
|
a
$400 million sublimit for the issuance of standby letters of
credit;
|
·
|
a
limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not
exceed 67.5 percent at the end of any calendar
quarter;
|
·
|
a
requirement that ONEOK maintains the power to control the management and
policies of ONEOK Partners,
|
·
|
a
limit on new investments in master limited partnerships;
and
|
·
|
other
customary affirmative and negative covenants, including covenants relating
to liens, investments, fundamental changes in ONEOK’s businesses, changes
in the nature of ONEOK’s businesses, transactions with affiliates, the use
of proceeds and a covenant that prevents ONEOK from restricting its
subsidiaries’ ability to pay
dividends.
|
The debt
covenant calculations in the ONEOK Credit Agreement and the 364-Day Facility
exclude the debt of ONEOK Partners. Upon breach of any covenant by
ONEOK, amounts outstanding under the ONEOK Credit Agreement or the 364-Day
Facility may become immediately due and payable. At December 31,
2008, ONEOK’s stand-alone debt-to-capital ratio was 58.2 percent, and ONEOK was
in compliance with all covenants under the ONEOK Credit Agreement and the ONEOK
364-Day Facility.
Under the
ONEOK Partners Credit Agreement, ONEOK Partners is required to comply with
certain financial, operational and legal covenants. Among other
things, these requirements include maintaining a ratio of indebtedness to
adjusted EBITDA (EBITDA plus minority interest in income of consolidated
subsidiaries, distributions received from investments and EBITDA related to any
approved capital projects less equity earnings from investments and the equity
portion of AFUDC) of no more than 5 to 1. If ONEOK Partners
consummates one or more acquisitions in which the aggregate purchase price is
$25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will
be increased to 5.5 to 1 for the three calendar quarters following the
acquisition. Upon any breach of any covenant by ONEOK Partners in its
ONEOK Partners Credit Agreement, amounts outstanding under the ONEOK Partners
Credit Agreement may become immediately due and payable. At December
31, 2008, ONEOK Partners’ ratio of indebtedness to adjusted EBITDA was 4.1 to 1,
and ONEOK Partners was in compliance with all covenants under the ONEOK Partners
Credit Agreement.
The
average interest rate on ONEOK and ONEOK Partners short-term debt outstanding at
December 31, 2008, was 4.51 percent and 4.22 percent, respectively, compared
with a weighted average rate of 3.88 percent and 3.94 percent, respectively, for
the year ended December 31, 2008. Based on the forward LIBOR curve,
we expect the interest rate on ONEOK and ONEOK Partners’ short-term borrowings
to decrease in 2009, compared with 2008.
Long-term Financing - In
addition to the principal sources of short-term liquidity discussed above,
options available to ONEOK to meet its longer-term cash requirements include the
issuance of equity, issuance of long-term notes, issuance of convertible debt
securities, asset securitization and sale/leaseback of
facilities. Options available to ONEOK Partners to meet its
longer-term cash requirements include the issuance of common units, issuance of
long-term notes, issuance of convertible debt securities, and asset
securitization and sale/leaseback of facilities.
ONEOK and
ONEOK Partners are subject, however, to changes in the equity and debt markets,
and there is no assurance they will be able or willing to access the public or
private markets in the future. ONEOK and ONEOK Partners may choose to
meet their cash requirements by utilizing some combination of cash flows from
operations, altering the timing of controllable expenditures, restricting future
acquisitions and capital projects, borrowing under existing credit facilities or
pursuing other debt or equity financing alternatives. Some of these
alternatives could involve higher costs or negatively affect their respective
credit ratings. Based on ONEOK’s and ONEOK Partners’ investment-grade
credit ratings, general financial condition and market expectations regarding
their future earnings and projected cash flows, ONEOK and ONEOK Partners believe
that they will be able to meet their respective cash requirements and maintain
their investment-grade credit ratings.
ONEOK Partners Debt
Issuance - In September 2007, ONEOK Partners completed an underwritten
public offering of $600 million aggregate principal amount of 6.85 percent
Senior Notes due 2037 (the 2037 Notes). The 2037 Notes were issued
under ONEOK Partners’ existing shelf registration statement filed with the
SEC.
ONEOK
Partners may redeem the 2037 Notes, in whole or in part, at any time prior to
their maturity at a redemption price equal to the principal amount of the 2037
Notes, plus accrued and unpaid interest and a make-whole premium. The
redemption price will never be less than 100 percent of the principal amount of
the 2037 Notes plus accrued and unpaid interest. The 2037 Notes are
senior unsecured obligations, ranking equally in right of payment with all of
ONEOK Partners’ existing and future unsecured senior indebtedness, and
effectively junior to all of the existing debt and other liabilities of its
non-guarantor subsidiaries. The 2037 Notes are non-recourse to
ONEOK.
Debt Covenants - The
terms of ONEOK’s long-term notes are governed by indentures containing covenants
that include, among other provisions, limitations on ONEOK’s ability to place
liens on its property or assets and its ability to sell and lease back its
property.
We filed
a new form of indenture in 2008. The new indenture includes covenants
that are similar to those contained in our prior indentures. The new
indenture does not limit the aggregate principal amount of debt securities that
may be issued and provides that debt securities may be issued from time to time
in one or more additional series.
The
indenture governing ONEOK Partners’ 2037 Notes does not limit the aggregate
principal amount of debt securities that may be issued and provides that debt
securities may be issued from time to time in one or more additional
series. The indenture contains covenants including, among other
provisions, limitations on ONEOK Partners’ ability to place liens on its
property or assets and its ability to sell and lease back its
property.
ONEOK
Partners’ $250 million and $225 million senior notes, due 2010 and 2011,
respectively, contain provisions that require ONEOK Partners to offer to
repurchase the senior notes at par value if its Moody’s or S&P credit rating
falls below investment grade (Baa3 for Moody’s or BBB- for S&P) and the
investment-grade rating is not reinstated within a period of 40
days. Further, the indentures governing ONEOK Partners’ senior notes
due 2010 and 2011 include an event of default
upon
acceleration of other indebtedness of $25 million or more and the indentures
governing the senior notes due 2012, 2016, 2036 and 2037 include 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,
2036 and 2037 to declare those notes immediately due and payable in
full.
ONEOK Partners Equity
Issuance - In March 2008, ONEOK
purchased from ONEOK Partners, in a private placement, an additional 5.4 million
of ONEOK Partners’ common units for a total purchase price of approximately
$303.2 million. In addition, ONEOK Partners completed a public
offering of 2.5 million common units at $58.10 per common unit and received net
proceeds of $140.4 million after deducting underwriting discounts but before
offering expenses. In conjunction with ONEOK Partners’ private
placement and the public offering of common units, ONEOK Partners GP contributed
$9.4 million to ONEOK Partners in order to maintain its 2 percent general
partner interest. ONEOK and ONEOK Partners GP funded these amounts
with available cash and short-term borrowings.
In April
2008, ONEOK Partners sold an additional 128,873 common units at $58.10 per
common unit to the underwriters of the public offering upon the partial exercise
of their option to purchase additional common units to cover
over-allotments. ONEOK Partners received net proceeds of
approximately $7.2 million from the sale of these common units after deducting
underwriting discounts but before offering expenses. In conjunction
with the partial exercise by the underwriters, ONEOK Partners GP contributed
$0.2 million to ONEOK Partners in order to maintain its 2 percent general
partner interest. Following these transactions, our interest in ONEOK
Partners is 47.7 percent.
ONEOK
Partners used a portion of the proceeds from the sale of common units and the
general partner contributions to repay borrowings under its existing ONEOK
Partners Credit Agreement.
Capital Expenditures - ONEOK’s
and ONEOK Partners’ capital expenditures are typically financed through
operating cash flows, short- and long-term debt and the issuance of
equity. Total capital expenditures for 2008 were $1,473.1 million,
compared with $883.7 million in 2007, exclusive of acquisitions. Of
these amounts, ONEOK Partners’ capital expenditures for 2008 were $1,253.9
million, compared with $709.9 million in 2007, exclusive of
acquisitions. The increase in capital expenditures for 2008, compared
with 2007, is driven primarily by ONEOK Partners’ internal capital projects
discussed beginning on page 37, and ONEOK’s purchase of ONEOK
Plaza. ONEOK and ONEOK Partners expect to continue to finance future
capital expenditures with a combination of operating cash flows, short- and
long-term debt, and the issuance of common units by ONEOK Partners.
The
following table summarizes our 2009 projected capital expenditures, excluding
AFUDC.
2009
Projected Capital Expenditures
|
|
|
|
|
(Millions
of dollars) |
ONEOK
Partners
|
|
|
|
$ |
425 |
|
|
Distribution
|
|
|
|
|
137 |
|
|
Energy
Services
|
|
|
|
|
- |
|
|
Other
|
|
|
|
|
19 |
|
|
Total
projected capital expenditures
|
|
|
|
$ |
581 |
|
|
Projected
2009 capital expenditures are significantly less than 2008 capital expenditures,
primarily due to the completion of the Overland Pass Pipeline and related
projects and the Guardian Pipeline expansion and
extension. Additional information about our capital expenditures is
included under “Capital Projects” on page 37. ONEOK Partners
anticipates spending $300 million to $500 million per year on growth capital
expenditures for the years 2010 through 2015.
Investment in Northern Border
Pipeline - Northern Border Pipeline anticipates an equity
contribution of approximately $85 million that will be required of its partners
in 2009, of which ONEOK Partners’ share will be approximately $43 million for
its 50 percent equity interest.
Credit Ratings - Our credit
ratings as of December 31, 2008, are shown in the table below.
|
|
ONEOK
|
|
|
ONEOK
Partners
|
Rating
Agency
|
|
Rating
|
|
Outlook
|
|
|
Rating
|
|
Outlook
|
Moody's
|
|
Baa2
|
|
Stable
|
|
|
Baa2
|
|
Stable
|
S&P
|
|
BBB
|
|
Stable
|
|
|
BBB
|
|
Stable
|
ONEOK’s
commercial paper is rated P2 by Moody’s and A2 by S&P. ONEOK’s
and ONEOK Partners’ credit ratings, which are currently investment grade, may be
affected by a material change in financial ratios or a material event affecting
the business. The most common criteria for assessment of credit
ratings are the debt-to-capital ratio, business risk profile, pretax and
after-tax interest coverage, and liquidity. ONEOK and ONEOK Partners
do not anticipate their respective credit ratings to be
downgraded. However, if our credit ratings were downgraded, the
interest rates on our commercial paper borrowings, the ONEOK Credit Agreement
and the 364-Day Facility would increase, resulting in an increase in our cost to
borrow funds, and we could potentially lose access to the commercial paper
market. Likewise, ONEOK Partners would see increased borrowing costs
under the ONEOK Partners Credit Agreement. In the event that ONEOK is
unable to borrow funds under its commercial paper program and there has not been
a material adverse change in its business, ONEOK would continue to have access
to the ONEOK Credit Agreement, which expires in July 2011, and the 364-Day
Facility, which expires in August 2009. An adverse rating change
alone is not a default under the ONEOK Credit Agreement, the 364-Day Facility or
the ONEOK Partners Credit Agreement but could trigger repurchase obligations
with respect to certain long-term debt. See additional discussion
about our credit ratings under “Debt Covenants.”
If ONEOK
Partners’ repurchase obligations are triggered, it may not have sufficient cash
on hand to repurchase and repay any accelerated senior notes, which may cause it
to borrow money under its credit facilities or seek alternative financing
sources to finance the repurchases and repayment. ONEOK Partners
could also face difficulties accessing capital or its borrowing costs could
increase, impacting its ability to obtain financing for acquisitions or capital
expenditures, to refinance indebtedness and to fulfill its debt
obligations.
Our
Energy Services segment relies upon the investment-grade rating of ONEOK’s
senior unsecured long-term debt to reduce its collateral
requirements. If ONEOK’s credit ratings were to decline below
investment grade, our ability to participate in energy marketing and trading
activities could be significantly limited. Without an
investment-grade rating, we may be required to fund margin requirements with our
counterparties with cash, letters of credit or other negotiable
instruments. At December 31, 2008, we could have been required to
fund approximately $36.2 million in margin requirements related to financial
contracts upon such a downgrade. A decline in ONEOK’s credit rating
below investment grade may also significantly impact other business
segments.
Other
than ONEOK Partners’ note repurchase obligations and the margin requirements for
our Energy Services segment described above, we have determined that we do not
have significant exposure to rating triggers under ONEOK’s trust indentures,
building leases, equipment leases and other various contracts. Rating
triggers are defined as provisions that would create an automatic default or
acceleration of indebtedness based on a change in our credit
rating.
In the
normal course of business, ONEOK’s and ONEOK Partners’ counterparties provide
secured and unsecured credit. In the event of a downgrade in ONEOK’s
or ONEOK Partners’ credit rating or a significant change in ONEOK’s or ONEOK
Partners’ counterparties’ evaluation of our creditworthiness, ONEOK or ONEOK
Partners could be asked to provide additional collateral in the form of cash,
letters of credit or other negotiable instruments.
ONEOK Partners’ Class B Units
- The units we received from ONEOK Partners were newly created Class B limited
partner units. Distributions on the Class B limited partner units
were prorated from the date of issuance. As of April 7, 2007, the
Class B limited partner units are no longer subordinated to distributions on
ONEOK Partners’ common units and generally have the same voting rights as the
common units.
At a
special meeting of the ONEOK Partners common unitholders held March 29, 2007,
the unitholders approved a proposal to permit the conversion of all or a portion
of the Class B limited partner units issued in the acquisition and consolidation
of certain companies comprising our former gathering and processing, natural gas
liquids, and pipelines and storage segments in a series of transactions
(collectively the ONEOK Transactions) into common units at the option of the
Class B unitholder. The March 29, 2007, special meeting was adjourned
to May 10, 2007, to allow unitholders additional time to vote on a proposal to
approve amendments to the ONEOK Partners’ Partnership Agreement, which had the
amendments been approved, would have granted voting rights for units held by us
and our affiliates if a vote is held to remove us as the general partner and
would have required fair market value compensation for our general partner
interest if we are removed as general partner. While a majority of
ONEOK Partners common unitholders voted in favor of the proposed amendments to
the ONEOK Partners Partnership Agreement at the reconvened meeting of the common
unitholders held May 10, 2007, the proposed amendments were not approved by the
required two-thirds affirmative vote of the outstanding units, excluding the
common units and Class B units held by us and our affiliates. As a
result, effective April 7, 2007, the Class B limited partner units are entitled
to receive increased quarterly distributions and distributions upon liquidation
equal to 110 percent of the distributions paid with respect to the common
units.
On June
21, 2007, we, as the sole holder of ONEOK Partners’ Class B limited partner
units, waived our right to receive the increased quarterly distributions on the
Class B units for the period April 7, 2007, through December 31, 2007,
and
continuing
thereafter until we give ONEOK Partners no less than 90 days advance notice that
we have withdrawn our waiver. Any such withdrawal of the waiver will
be effective with respect to any distribution on the Class B units declared or
paid on or after 90 days following delivery of the notice.
In
addition, since the proposed amendments to the ONEOK Partners’ Partnership
Agreement were not approved by the common unitholders, if the common unitholders
vote at any time to remove us or our affiliates as the general partner,
quarterly distributions payable on 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.
Stock Repurchase Plan - For
more information regarding the Stock Repurchase Plan, refer to discussion in
Note G of the Notes to Consolidated Financial Statements in this Annual Report
on Form 10-K.
Commodity Prices - We are
subject to commodity price volatility. Significant fluctuations in
commodity price in either physical or financial energy contracts may impact our
overall liquidity due to the impact the commodity price changes have on our cash
flows from operating activities, including the impact on working capital for
NGLs and natural gas held in storage, margin requirements and certain
energy-related receivables. We believe that ONEOK’s and ONEOK
Partners’ available credit and cash and cash equivalents are adequate to meet
liquidity requirements associated with commodity price
volatility. See discussion beginning on page 63 under “Commodity
Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market
Risk for information on our hedging activities.
Pension and Postretirement Benefit
Plans - Information about our pension and postretirement benefits plans,
including anticipated contributions, is included under Note J of the Notes
to Consolidated Financial Statements in this Annual Report on Form 10-K.
At
December 31, 2007, the funded status of our pension plans exceeded 94 percent as
required by federal regulations. General market factors in 2008
negatively impacted the fair value of our plan assets, and as a result, we made
a voluntary contribution to our pension plans of $112 million on December 31,
2008. We do not expect that our funding requirements in 2009 will
have a material impact on our liquidity.
ENVIRONMENTAL
LIABILITIES
Information
about our environmental liabilities is included in Note K of the Notes to
Consolidated Financial Statements in this Annual Report on Form
10-K.
CASH
FLOW ANALYSIS
We use
the indirect method to prepare our Consolidated Statements of Cash
Flows. Under this method, we reconcile net income to cash flows
provided by operating activities by adjusting net income for those items that
impact net income but may not result in actual cash receipts or payments during
the period. These reconciling items include depreciation and
amortization, allowance for equity funds used during construction, gain on sale
of assets, minority interests in income of consolidated affiliates,
undistributed earnings from equity investments in excess of distributions
received, deferred income taxes, stock-based compensation expense, allowance for
doubtful accounts, inventory adjustments and investment securities
gains. The following table sets forth the changes in cash flows by
operating, investing and financing activities for the periods
indicated.
|
|
|
|
|
|
Variances
|
|
Variances
|
|
|
Years
Ended December 31,
|
|
2008
vs. 2007
|
|
2007
vs. 2006
|
|
|
2008
|
|
2007
|
|
2006
|
|
Increase
(Decrease)
|
|
Increase
(Decrease)
|
|
|
(Millions
of dollars)
|
|
Total
cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
activities
|
|
$ |
475.7 |
|
$ |
1,029.7 |
|
$ |
873.3 |
|
$ |
(554.0 |
) |
(54 |
%) |
|
$ |
156.4 |
|
18 |
% |
Investing
activities
|
|
|
(1,454.3 |
) |
|
(1,151.8 |
) |
|
(237.2 |
) |
|
(302.5 |
) |
(26 |
%) |
|
|
(914.6 |
) |
* |
|
Financing
activities
|
|
|
1,469.6 |
|
|
72.9 |
|
|
(618.8 |
) |
|
1,396.7 |
|
* |
|
|
|
691.7 |
|
* |
|
Change
in cash and cash equivalents
|
|
|
491.0 |
|
|
(49.2 |
) |
|
17.3 |
|
|
540.2 |
|
* |
|
|
|
(66.5 |
) |
* |
|
Cash
and cash equivalents at beginning of period
|
|
|
19.1 |
|
|
68.3 |
|
|
7.9 |
|
|
(49.2 |
) |
(72 |
%) |
|
|
60.4 |
|
* |
|
Effect
of Accounting Change
on
Cash and Cash Equivalents
|
|
|
- |
|
|
- |
|
|
43.1 |
|
|
- |
|
0 |
% |
|
|
(43.1 |
) |
(100 |
%) |
Cash
and cash equivalents at end of period
|
|
$ |
510.1 |
|
$ |
19.1 |
|
$ |
68.3 |
|
$ |
491.0 |
|
* |
|
|
$ |
(49.2 |
) |
(72 |
%) |
*
Percentage change is greater than 100 percent.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Cash Flows -
Operating cash flows decreased by $554.0 million for 2008, compared with 2007,
primarily due to changes in working capital. These changes decreased
operating cash flows by $515.3 million for 2008, compared with an increase of
$203.6 million for 2007, primarily due to decreases in accounts payable and
increased funding for our pension plans, partially offset by decreases in
accounts and notes receivable. The decrease in operating cash flows
due to increases in working capital for 2008 was partially offset by higher net
income.
Operating
cash flows increased by $156.4 million for 2007, compared with
2006. Working capital increased operating cash flows by $203.6
million for 2007, compared with an increase of $59.7 million for
2006.
Investing Cash Flows - The
increased use of cash during 2008 was primarily related to a $589.4 million
increase in capital expenditures, compared with 2007. Capital
expenditures increased $507.4 for 2007, compared with 2006. These
increases are primarily related to ONEOK Partners’ capital
projects.
In
October 2007, ONEOK Partners acquired an interstate natural gas liquids and
refined petroleum products pipeline system and related assets from a subsidiary
of Kinder Morgan for approximately $300 million, before working capital
adjustments.
In April
2006, our ONEOK Partners segment received $297.0 million for the sale of a 20
percent partnership interest in Northern Border Pipeline. Our Energy
Services segment received $53.0 million for the sale of our discontinued
component, Spring Creek, in October 2006.
Acquisitions
in 2006 primarily relate to our ONEOK Partners segment acquiring the 66-2/3
percent interest in Guardian Pipeline not previously owned by ONEOK Partners for
approximately $77 million. We also purchased from TransCanada its
17.5 percent general partner interest in ONEOK Partners for $40
million. Additionally, ONEOK Partners paid $11.6 million to Williams
for a 99 percent interest in, and initial capital expenditures related to, the
Overland Pass Pipeline Company natural gas liquids pipeline joint
venture.
We had a
decrease in short-term investments of $31.1 million for 2007, compared with a
total investment of $31.1 million for 2006. During 2007, we had less
cash to invest following our repurchase of 7.5 million shares of our outstanding
common stock in June.
Investing
cash flows for 2006 also include the impact of the deconsolidation of Northern
Border Pipeline and consolidation of Guardian Pipeline.
Financing Cash Flows - Net
short-term borrowings were $2.1 billion for 2008, compared with $196.6 million
for 2007. The increased short-term borrowings during 2008 were used
to repay a portion of $402.3 million of maturing long-term
debt. Short-term borrowings also increased as the result ONEOK’s and
ONEOK Partners’ decision in late 2008 to borrow under their available credit
facilities to fund their respective anticipated working capital requirements for
the remainder of 2008 and into 2009, and ONEOK Partners’ capital
projects.
During
2008, ONEOK Partners’ public sale of 2.6 million common units generated
approximately $147 million, after deducting underwriting discounts but before
offering expenses.
In 2007,
short-term financing was primarily used to fund ONEOK Partners’ capital
projects. ONEOK Partners’ $598 million debt issuance, net of
discounts, was used to repay borrowings under the ONEOK Partners Credit
agreement and finance the $300 million acquisition of assets, before working
capital adjustments, from a subsidiary of Kinder Morgan in October
2007.
In 2006,
we repaid the remaining $900 million outstanding on our $1.0 billion short-term
bridge financing agreement. During the second quarter of 2006, ONEOK
Partners borrowed $1.05 billion under its $1.1 billion 364-day credit facility
dated April 6, 2006, (Bridge Facility) to finance a portion of the acquisition
of the ONEOK Energy Assets and $77 million under its then existing credit
agreement to acquire the 66-2/3 percent interest in Guardian Pipeline not
previously owned by ONEOK Partners. During the third quarter of 2006,
ONEOK Partners completed the underwritten public offering of senior notes
totaling $1.4 billion in net proceeds, before offering expenses, which were used
to repay all of the amounts outstanding of the $1.05 billion borrowed under the
ONEOK Partners Bridge Facility and to repay $335 million of indebtedness
outstanding under its then existing credit agreement.
On
February 16, 2006, we successfully settled our 16.1 million equity units to 19.5
million shares of our common stock. With the settlement of the equity
units, we received $402.4 million in cash, which we used to repay a portion of
our commercial paper. We repaid a total of $641.5 million of our
commercial paper during 2006. See Note G of the Notes to Consolidated
Financial Statements in this Annual Report on Form 10-K for additional
discussion regarding the equity unit conversion.
In March
2006, our ONEOK Partners segment borrowed $33 million under its then existing
credit agreement to redeem all of the outstanding Viking Gas Transmission Series
A, B, C and D senior notes and paid a redemption premium of $3.6
million.
During
2007, we paid $20.1 million for the settlement of the forward purchase contract
related to our stock repurchase in February and approximately $370 million for
our stock repurchase in June. We paid $281.4 million to repurchase
shares in August 2006.
CONTRACTUAL
OBLIGATIONS AND COMMERCIAL COMMITMENTS
The
following table sets forth our contractual obligations related to debt,
operating leases and other long-term obligations as of December 31,
2008. For additional discussion of the debt and operating lease
agreements, see Notes I and K, respectively, of the Notes to the Consolidated
Financial Statements in this Annual Report on Form 10-K.
|
|
Payments
Due by Period
|
|
Contractual
Obligations
|
|
Total
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
Thereafter
|
|
ONEOK
|
|
(Thousands
of dollars)
|
|
$1.2
billion credit agreement
|
|
$ |
1,100,000 |
|
$ |
1,100,000 |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
$400
million credit agreement
|
|
|
300,000 |
|
|
300,000 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
Long-term
debt
|
|
|
1,584,053 |
|
|
106,265 |
|
|
6,284 |
|
|
406,306 |
|
|
6,329 |
|
|
6,205 |
|
|
1,052,664 |
|
Interest
payments on debt
|
|
|
1,100,500 |
|
|
92,100 |
|
|
91,400 |
|
|
70,900 |
|
|
62,100 |
|
|
61,700 |
|
|
722,300 |
|
Operating
leases
|
|
|
300,795 |
|
|
88,837 |
|
|
55,888 |
|
|
61,232 |
|
|
32,943 |
|
|
25,376 |
|
|
36,519 |
|
Firm
transportation contracts
|
|
|
552,509 |
|
|
123,352 |
|
|
103,157 |
|
|
81,833 |
|
|
80,389 |
|
|
57,249 |
|
|
106,529 |
|
Financial
and physical derivatives
|
|
|
927,635 |
|
|
816,319 |
|
|
97,225 |
|
|
13,623 |
|
|
468 |
|
|
- |
|
|
- |
|
Employee
benefit plans
|
|
|
42,602 |
|
|
42,602 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
Other
|
|
|
850 |
|
|
567 |
|
|
283 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
|
$ |
5,908,944 |
|
$ |
2,670,042 |
|
$ |
354,237 |
|
$ |
633,894 |
|
$ |
182,229 |
|
$ |
150,530 |
|
$ |
1,918,012 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ONEOK
Partners
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1
billion credit agreement
|
|
$ |
870,000 |
|
$ |
870,000 |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
$ |
- |
|
Long-term
debt
|
|
|
2,596,711 |
|
|
11,931 |
|
|
261,931 |
|
|
236,931 |
|
|
361,062 |
|
|
7,650 |
|
|
1,717,206 |
|
Interest
payments on debt
|
|
|
2,686,400 |
|
|
176,700 |
|
|
163,700 |
|
|
140,000 |
|
|
120,200 |
|
|
114,300 |
|
|
1,971,500 |
|
Operating
leases
|
|
|
86,508 |
|
|
18,362 |
|
|
16,027 |
|
|
15,527 |
|
|
8,755 |
|
|
2,063 |
|
|
25,774 |
|
Firm
transportation contracts
|
|
|
14,765 |
|
|
11,086 |
|
|
3,679 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
Financial
and physical derivatives
|
|
|
48,467 |
|
|
48,467 |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
Purchase
commitments,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
rights-of-way
and other
|
|
|
35,582 |
|
|
30,914 |
|
|
977 |
|
|
976 |
|
|
977 |
|
|
977 |
|
|
761 |
|
|
|
$ |
6,338,433 |
|
$ |
1,167,460 |
|
$ |
446,314 |
|
$ |
393,434 |
|
$ |
490,994 |
|
$ |
124,990 |
|
$ |
3,715,241 |
|
Total
|
|
$ |
12,247,377 |
|
$ |
3,837,502 |
|
$ |
800,551 |
|
$ |
1,027,328 |
|
$ |
673,223 |
|
$ |
275,520 |
|
$ |
5,633,253 |
|
Long-term Debt -
Long-term debt as reported in our Consolidated Balance Sheets includes
unamortized debt discount and the mark-to-market effect of interest-rate
swaps.
Interest Payments on
Debt - Interest expense is calculated by multiplying long-term debt by
the respective coupon rates, adjusted for active swaps.
Operating Leases -
Our operating leases include a natural gas processing plant, storage contracts,
office space, pipeline equipment, rights of way and
vehicles. Operating lease obligations for ONEOK exclude
intercompany payments related to the lease of a gas processing
plant.
Firm Transportation
Contracts - Our ONEOK Partners, Distribution and Energy Services segments
are party to fixed-price transportation contracts. However, the costs
associated with our Distribution segment’s contracts are recovered through rates
as allowed by the applicable regulatory agency and are excluded from the table
above. Firm transportation agreements with our ONEOK Partners
segment’s natural gas gathering and processing joint ventures require minimum
monthly payments.
Financial and Physical
Derivatives - These are obligations arising from our ONEOK Partners and
Energy Services segments’ physical and financial derivatives for fixed-price
purchase commitments and are based on market information at December 31,
2008. Not included in these amounts are offsetting cash inflows from
our Energy Services segment’s product sales and net positive
settlements. As market information changes daily and is potentially
volatile,
these values may change significantly. Additionally, product sales
may require additional purchase obligations to fulfill sales obligations that
are not reflected in these amounts.
Employee Benefit
Plans - Employee benefit plans include our minimum required contribution
to our pension and postretirement benefit plans for 2009. See Note J
of the Notes to Consolidated Financial Statements in this Annual Report on Form
10-K for discussion of our employee benefit plans.
Purchase Commitments
- Purchase commitments include commitments related to ONEOK Partners’ growth
capital expenditures and other rights of way commitments. Purchase
commitments exclude commodity purchase contracts, which are included in the
“Financial and physical derivatives” amounts.
FORWARD-LOOKING
STATEMENTS
Some of
the statements contained and incorporated in this Annual Report on Form 10-K are
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of
1934, as amended. The forward-looking statements relate to our
anticipated financial performance, management’s plans and objectives for our
future operations, our business prospects, the outcome of regulatory and legal
proceedings, market conditions and other matters. We make these
forward-looking statements in reliance on the safe harbor protections provided
under the Private Securities Litigation Reform Act of 1995. The
following discussion is intended to identify important factors that could cause
future outcomes to differ materially from those set forth in the forward-looking
statements.
Forward-looking
statements include the items identified in the preceding paragraph, the
information concerning possible or assumed future results of our operations and
other statements contained or incorporated in this Annual Report on Form 10-K
identified by words such as “anticipate,” “estimate,” “expect,” “project,”
“intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “could,” “may,”
“continue,” “might,” “potential,” “scheduled,” and other words and terms of
similar meaning.
You
should not place undue reliance on forward-looking statements. Known
and unknown risks, uncertainties and other factors may cause our actual results,
performance or achievements to be materially different from any future results,
performance or achievements expressed or implied by forward-looking
statements. Those factors may affect our operations, markets,
products, services and prices. In addition to any assumptions and
other factors referred to specifically in connection with the forward-looking
statements, factors that could cause our actual results to differ materially
from those contemplated in any forward-looking statement include, among others,
the following:
·
|
the
effects of weather and other natural phenomena on our operations,
including energy sales and demand for our services and energy
prices;
|
·
|
competition
from other United States and Canadian energy suppliers and transporters as
well as alternative forms of energy, including, but not limited to,
biofuels such as ethanol and
biodiesel;
|
·
|
the
status of deregulation of retail natural gas
distribution;
|
·
|
the
capital intensive nature of our
businesses;
|
·
|
the
profitability of assets or businesses acquired or constructed by
us;
|
·
|
our
ability to make cost-saving changes in
operations;
|
·
|
risks
of marketing, trading and hedging activities, including the risks of
changes in energy prices or the financial condition of our
counterparties;
|
·
|
the
uncertainty of estimates, including accruals and costs of environmental
remediation;
|
·
|
the
timing and extent of changes in energy commodity
prices;
|
·
|
the
effects of changes in governmental policies and regulatory actions,
including changes with respect to income and other taxes, environmental
compliance, climate change initiatives, and authorized rates or recovery
of gas and gas transportation
costs;
|
·
|
the
impact on drilling and production by factors beyond our control, including
the demand for natural gas and refinery-grade crude oil; producers’ desire
and ability to obtain necessary permits; reserve performance; and capacity
constraints on the pipelines that transport crude oil, natural gas and
NGLs from producing areas and our
facilities;
|
·
|
changes
in demand for the use of natural gas because of market conditions caused
by concerns about global warming;
|
·
|
the
impact of unforeseen changes in interest rates, equity markets, inflation
rates, economic recession and other external factors over which we have no
control, including the effect on pension expense and funding resulting
from changes in stock and bond market
returns;
|
·
|
our
indebtedness could make us vulnerable to general adverse economic and
industry conditions, limit our ability to borrow additional funds, and/or
place us at competitive disadvantages compared to our competitors that
have less debt, or have other adverse
consequences;
|
·
|
actions
by rating agencies concerning the credit ratings of ONEOK and ONEOK
Partners;
|
·
|
the
results of administrative proceedings and litigation, regulatory actions
and receipt of expected clearances involving the OCC, KCC, Texas
regulatory authorities or any other local, state or federal regulatory
body, including the FERC;
|
·
|
our
ability to access capital at competitive rates or on terms acceptable to
us;
|
·
|
risks
associated with adequate supply to our gathering, processing,
fractionation and pipeline facilities, including production declines that
outpace new drilling;
|
·
|
the
risk that material weaknesses or significant deficiencies in our internal
controls over financial reporting could emerge or that minor problems
could become significant;
|
·
|
the
impact and outcome of pending and future
litigation;
|
·
|
the
ability to market pipeline capacity on favorable terms, including the
effects of:
|
-
|
future
demand for and prices of natural gas and
NGLs;
|
-
|
competitive
conditions in the overall energy
market;
|
-
|
availability
of supplies of Canadian and United States natural gas;
and
|
-
|
availability
of additional storage capacity;
|
·
|
performance
of contractual obligations by our customers, service providers,
contractors and shippers;
|
·
|
the
timely receipt of approval by applicable governmental entities for
construction and operation of our pipeline and other projects and required
regulatory clearances;
|
·
|
our
ability to acquire all necessary permits, consents or other approvals in a
timely manner, to promptly obtain all necessary materials and supplies
required for construction, and to construct gathering, processing,
storage, fractionation and transportation facilities without labor or
contractor problems;
|
·
|
the
mechanical integrity of facilities
operated;
|
·
|
demand
for our services in the proximity of our
facilities;
|
·
|
our
ability to control operating costs;
|
·
|
adverse
labor relations;
|
·
|
acts
of nature, sabotage, terrorism or other similar acts that cause damage to
our facilities or our suppliers’ or shippers’
facilities;
|
·
|
economic
climate and growth in the geographic areas in which we do
business;
|
·
|
the
risk of a prolonged slowdown in growth or decline in the United States
economy or the risk of delay in growth recovery in the United States
economy, including increasing liquidity risks in United States credit
markets;
|
·
|
the
impact of recently issued and future accounting pronouncements and other
changes in accounting policies;
|
·
|
the
possibility of future terrorist attacks or the possibility or occurrence
of an outbreak of, or changes in, hostilities or changes in the political
conditions in the Middle East and
elsewhere;
|
·
|
the
risk of increased costs for insurance premiums, security or other items as
a consequence of terrorist attacks;
|
·
|
risks
associated with pending or possible acquisitions and dispositions,
including our ability to finance or integrate any such acquisitions and
any regulatory delay or conditions imposed by regulatory bodies in
connection with any such acquisitions and
dispositions;
|
·
|
the
possible loss of gas distribution franchises or other adverse effects
caused by the actions of
municipalities;
|
·
|
the
impact of unsold pipeline capacity being greater or less than
expected;
|
·
|
the
ability to recover operating costs and amounts equivalent to income taxes,
costs of property, plant and equipment and regulatory assets in our state
and FERC-regulated rates;
|
·
|
the
composition and quality of the natural gas and NGLs we gather and process
in our plants and transport on our
pipelines;
|
·
|
the
efficiency of our plants in processing natural gas and extracting and
fractionating NGLs;
|
·
|
the
impact of potential impairment
charges;
|
·
|
the
risk inherent in the use of information systems in our respective
businesses, implementation of new software and hardware, and the impact on
the timeliness of information for financial
reporting;
|
·
|
our
ability to control construction costs and completion schedules of our
pipelines and other projects; and
|
·
|
the
risk factors listed in the reports we have filed and may file with the
SEC, which are incorporated by
reference.
|
These
factors are not necessarily all of the important factors that could cause actual
results to differ materially from those expressed in any of our forward-looking
statements. Other factors could also have material adverse effects on
our future results. These and other risks are described in greater
detail in Item 1A, Risk Factors, in this Annual Report on Form
10-K. All forward-looking statements attributable to us or persons
acting on our behalf are expressly qualified in their entirety by these
factors. Other than as required under securities laws, we undertake
no obligation to update publicly any forward-looking statement whether as a
result of new information, subsequent events or change in circumstances,
expectations or otherwise.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
Risk Policy and Oversight - We
control the scope of risk management, marketing and trading operations through a
comprehensive set of policies and procedures involving senior levels of
management. The Audit Committee of our Board of Directors has
oversight responsibilities for our risk management limits and
policies. Our risk oversight committee, comprised of corporate and
business segment officers, oversees all activities related to commodity price
and credit risk management, and marketing and trading activities. The
committee also monitors risk metrics including value-at-risk (VAR) and
mark-to-market losses. We have a risk control group that is assigned
responsibility for establishing and enforcing the policies and procedures and
monitoring certain risk metrics. Key risk control activities include
risk measurement and monitoring, validation of transactions, portfolio
valuation, VAR and other risk metrics.
Our
exposure to market risk discussed below includes forward-looking statements and
represents an estimate of possible changes in future earnings that would occur
assuming hypothetical future movements in interest rates or commodity
prices. Our views on market risk are not necessarily indicative of
actual results that may occur and do not represent the maximum possible gains
and losses that may occur since actual gains and losses will differ from those
estimated based on actual fluctuations in interest rates or commodity prices and
the timing of transactions.
COMMODITY
PRICE RISK
We are
exposed to commodity price risk and the impact of market price fluctuations of
natural gas, NGLs and crude oil prices. Commodity price risk refers
to the risk of loss in cash flows and future earnings arising from adverse
changes in commodity energy prices. To minimize the risk from market
price fluctuations of natural gas, NGLs and crude oil, we use commodity
derivative instruments such as futures, physical forward contracts, swaps and
options to manage commodity price risk associated with existing or anticipated
purchase and sale agreements, existing physical natural gas in storage, and
basis risk.
ONEOK
Partners
ONEOK
Partners is exposed to commodity price risk, primarily with respect to NGLs, as
a result of receiving commodities in exchange for its gathering and processing
services. To a lesser extent, ONEOK Partners is exposed to the
relative price differential between NGLs and natural gas, or the gross
processing spread, with respect to its keep-whole processing
contracts. ONEOK Partners is also exposed to the risk of price
fluctuations and the cost of intervening transportation at various market
locations. As part of ONEOK Partners’ hedging strategy, ONEOK
Partners uses commodity fixed-price physical forwards and derivative contracts,
including NYMEX-based futures and over-the-counter swaps, to minimize earnings
volatility in its natural gas gathering and processing business related to
natural gas, NGL and condensate price fluctuations.
ONEOK
Partners reduces its gross processing spread exposure through a combination of
physical and financial hedges. ONEOK Partners utilizes a portion of
its percent-of-proceeds equity natural gas as an offset, or natural hedge, to an
equivalent portion of its keep-whole shrink requirements. This has
the effect of converting ONEOK Partners’ gross processing spread risk to NGL
commodity price risk, and ONEOK Partners then uses financial instruments to
hedge the sale of NGLs.
The
following table sets forth ONEOK Partners’ hedging information for the year
ending December 31, 2009.
|
Year
Ending December 31, 2009
|
|
Volumes
Hedged
|
|
|
Average
Price
|
Percentage
Hedged
|
NGLs
(Bbl/d)
(a)
|
5,010
|
|
|
$ |
1.18
|
/
gallon
|
57%
|
Condensate
(Bbl/d)
(a)
|
666
|
|
|
$ |
3.23
|
/
gallon
|
32%
|
Total
liquid sales (Bbl/d)
|
5,676
|
|
|
$ |
1.42
|
/
gallon
|
52%
|
(a)
- Hedged with fixed-price swaps.
|
|
|
|
|
|
|
|
ONEOK
Partners’ commodity price risk is estimated as a hypothetical change in the
price of NGLs, crude oil and natural gas at December 31, 2008, excluding the
effects of hedging and assuming normal operating conditions. ONEOK
Partners’ condensate sales are based on the price of crude oil. ONEOK
Partners estimates the following:
·
|
a
$0.01 per gallon decrease in the composite price of NGLs would decrease
annual net margin by approximately $1.2
million;
|
·
|
a
$1.00 per barrel decrease in the price of crude oil would decrease annual
net margin by approximately $1.0 million;
and
|
·
|
a
$0.10 per MMBtu decrease in the price of natural gas would decrease annual
net margin by approximately $0.6
million.
|
The above
estimates of commodity price risk do not include any effects on demand for its
services that might be caused by, or arise in conjunction with, price
changes. For example, a change in the gross processing spread may
cause a change in the amount of ethane extracted from the natural gas stream,
impacting gathering and processing margins, NGL exchange revenues, natural gas
deliveries, and NGL volumes shipped and fractionated.
ONEOK
Partners is also exposed to commodity price risk primarily as a result of NGLs
in storage, the relative values of the various NGL products to each other, the
relative value of NGLs to natural gas and the relative value of NGL purchases at
one location and sales at another location, known as basis
risk. ONEOK Partners utilizes fixed-price physical forward contracts
to reduce earnings volatility related to NGL price
fluctuations. ONEOK Partners has not entered into any financial
instruments with respect to its NGL marketing activities.
In
addition, ONEOK Partners is exposed to commodity price risk as its natural gas
interstate and intrastate pipelines collect natural gas from its customers for
operations or as part of its fee for services provided. When the
amount of natural gas consumed in operations by these pipelines differs from the
amount provided by its customers, the pipelines must buy or sell natural gas, or
store or use natural gas from inventory, which exposes ONEOK Partners to
commodity price risk. At December 31, 2008, there were no hedges in
place with respect to natural gas price risk from ONEOK Partners’ natural gas
pipeline business.
Distribution
Our
Distribution segment uses derivative instruments to hedge the cost of
anticipated natural gas purchases during the winter heating months to protect
their customers from upward volatility in the market price of natural
gas. Gains or losses associated with these derivative instruments are
included in, and recoverable through, the monthly purchased gas cost
mechanism.
Energy
Services
Our
Energy Services segment is exposed to commodity price risk, basis risk and price
volatility arising from natural gas in storage, requirement contracts, asset
management contracts and index-based purchases and sales of natural gas at
various market locations. We minimize the volatility of our exposure
to commodity price risk through the use of derivative instruments, which, under
certain circumstances, are designated as cash flow or fair value
hedges. We are also exposed to commodity price risk from fixed-price
purchases and sales of natural gas, which we hedge with derivative
instruments. Both the fixed-price purchases and sales and related
derivatives are recorded at fair value.
Fair Value Component of the Energy
Marketing and Risk Management Assets and Liabilities - The following
table sets forth the fair value component of the energy marketing and risk
management assets and liabilities, excluding $21.0 million of net liabilities
from derivative instruments declared as either fair value or cash flow
hedges.
Fair
Value Component of Energy Marketing and Risk Management Assets and
Liabilities
|
|
|
|
(Thousands
of dollars) |
Net
fair value of derivatives outstanding at December 31, 2007
|
|
|
$ |
25,171 |
|
|
Derivatives
reclassified or otherwise settled during the period
|
|
|
|
(55,874 |
) |
|
Fair
value of new derivatives entered into during the period
|
|
|
|
236,772 |
|
|
Other
changes in fair value
|
|
|
|
52,731 |
|
|
Net
fair value of derivatives outstanding at December 31, 2008
(a)
|
|
|
$ |
258,800 |
|
|
|
|
|
|
|
|
|
(a)
- The maturities of derivatives are based on injection and withdrawal
periods from
April
through March, which is consistent with our business strategy. The
maturities
are
as follows: $225.0 million matures through March 2009, $33.9 million
matures
through
March 2012 and $(0.1) million matures through March 2014.
|
|
|
The
change in the net fair value of derivatives outstanding includes the effect of
settled energy contracts and current period changes resulting primarily from
newly originated transactions and the impact of market movements on the fair
value of energy marketing and risk management assets and
liabilities. Fair value of new derivatives entered into during the
period includes $298.8 million of cash flow hedges reclassified into earnings
from accumulated other comprehensive income (loss) related to the write-down of
our natural gas in storage to its lower of weighted-average cost or
market.
For
further discussion of fair value measurements and trading activities and
assumptions used in our trading activities, see the “Critical Accounting
Policies and Estimates” section of Item 7, Management’s Discussion and Analysis
of Financial Condition and Results of Operation. Also, see Notes C
and D of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K.
Value-at-Risk (VAR) Disclosure of
Commodity Price Risk - We measure commodity
price risk in our Energy Services segment using a VAR methodology, which
estimates the expected maximum loss of our portfolio over a specified time
horizon within a given confidence interval. Our VAR calculations are
based on the Monte Carlo approach. The quantification of commodity
price risk using VAR provides a consistent measure of risk across diverse energy
markets and products with different risk factors in order to set overall risk
tolerance and to determine risk thresholds. The use of this
methodology requires a number of key assumptions, including the selection of a
confidence level and the holding period to liquidation. Inputs to the
calculation include prices, volatilities, positions, instrument valuations and
the variance-covariance matrix. Historical data is used to estimate
our VAR with more weight given to recent data, which is considered a more
relevant predictor of immediate future commodity market movements. We
rely on VAR to determine the potential reduction in the portfolio values arising
from changes in market conditions over a defined period. While
management believes that the referenced assumptions and approximations are
reasonable, no uniform industry methodology exists for estimating
VAR. Different assumptions and approximations could produce
materially different VAR estimates.
Our VAR
exposure represents an estimate of potential losses that would be recognized due
to adverse commodity price movements in our Energy Services segment’s portfolio
of derivative financial instruments, physical commodity contracts, leased
transport, storage capacity contracts and natural gas in storage. A
one-day time horizon and a 95 percent confidence level are used in our VAR
data. Actual future gains and losses will differ from those estimated
by the VAR calculation based on actual fluctuations in commodity prices,
operating exposures and timing thereof, and the changes in our derivative
financial instruments, physical contracts and natural gas in
storage. VAR information should be evaluated in light of these
assumptions and the methodology’s other limitations.
The
potential impact on our future earnings, as measured by VAR, was $7.9 million
and $6.0 million at December 31, 2008 and 2007, respectively. The
following table details the average, high and low VAR calculations for the
periods indicated.
|
Years
Ended December 31,
|
Value-at-Risk
|
|
2008
|
|
|
2007
|
|
|
(Millions
of dollars)
|
Average
|
|
$ |
12.3 |
|
|
$ |
8.9 |
|
High
|
|
$ |
24.9 |
|
|
$ |
23.0 |
|
Low
|
|
$ |
4.0 |
|
|
$ |
3.4 |
|
Our VAR
calculation includes derivatives, executory storage and transportation
agreements and their related hedges. The variations in the VAR data
are reflective of market volatility and changes in our portfolio during the
year. The increase in average VAR for 2008, compared with 2007, was
primarily due to a significant increase in natural gas prices during the second
quarter of 2008.
Our VAR
calculation uses historical prices, placing more emphasis on the most recent
price movements. We revised our assumptions in the third quarter of
2008 to decrease the weight given to the most recent price changes and spread
the relative weighting over more historical data. This methodology
reduces the effects of the market anomalies and better reflects an efficient
market. We believe this methodology is more reflective of portfolio
risk and have applied the change on a prospective basis.
During
2008, we also began calculating the VAR on our mark-to-market derivative
positions, which reflects the risk associated with derivatives whose change in
fair value will impact current period earnings. These transactions
are subject to mark-to-market accounting treatment because they are not part of
a hedging relationship under Statement 133. VAR associated with these
derivative positions was not material during 2008. To the extent open
commodity positions exist, fluctuating commodity prices can impact our financial
results and financial position either favorably or unfavorably. As a
result, we cannot predict with precision the impact risk management decisions
may have on the business, operating results or financial
position.
INTEREST
RATE RISK
General - We are subject to
the risk of interest-rate fluctuation in the normal course of
business. We manage interest-rate risk through the use of fixed-rate
debt, floating-rate debt and, at times, interest-rate
swaps. Fixed-rate swaps are used to reduce our risk of increased
interest costs during periods of rising interest rates. Floating-rate
swaps are used to convert the fixed rates of long-term borrowings into
short-term variable rates. At December 31, 2008, the interest rate on
89.3 percent of our long-term debt, exclusive of the debt of our ONEOK Partners
segment, was fixed after considering the impact of interest-rate
swaps. At December 31, 2008, the interest rate on all of ONEOK
Partners’ long-term debt was fixed.
We
terminated a $100 million interest-rate swap in the fourth quarter of
2008. The total value we received was $19.2 million, which includes
$0.3 million of swap savings previously recorded. The remaining
savings of $18.9 million will be recognized in interest expense over the
remaining term of the debt instrument originally hedged.
In the
fourth quarter of 2008, our counterparties exercised the option to terminate two
additional interest-rate swap agreements totaling $140 million. The
swap terminations were effective in December 2008 and January
2009. The total value we received for the terminated swaps was not
material.
At
December 31, 2008, a 100 basis point move in the annual interest rate on all of
our swapped long-term debt would change our annual interest expense by $1.7
million before taxes. This 100 basis point change assumes a parallel
shift in the yield curve. If interest rates changed significantly, we
would take actions to manage our exposure to the change. Since a
specific action and the possible effects are uncertain, no change has been
assumed.
Fair Value Hedges - See Note D
of the Notes to Consolidated Financial Statements in this Annual Report on Form
10-K for discussion of the impact of interest-rate swaps and net interest
expense savings from terminated swaps.
Total net
swap savings for 2008 were $17.4 million, compared with $8.2 million for
2007. Total swap savings for 2009 are expected to be $10.5
million.
CURRENCY
EXCHANGE RATE RISK
As a
result of our Energy Services segment’s operations in Canada, we are exposed to
currency exchange rate risk from our commodity purchases and sales related to
our firm transportation and storage contracts. To reduce our exposure
to exchange-rate fluctuations, we use physical forward transactions, which
result in an actual two-way flow of currency on the settlement date since we
exchange U.S. dollars for Canadian dollars with another party. We
have not designated these transactions for hedge accounting treatment;
therefore, the gains and losses associated with the change in fair value are
recorded in net margin. At December 31, 2008 and 2007, our exposure
to risk from currency translation was not material. We recognized a
currency translation loss of $3.1 million during 2008 and currency translation
gains of $4.1 million and $2.5 million during 2007 and 2006,
respectively.
COUNTERPARTY
CREDIT RISK
ONEOK and
ONEOK Partners assess the creditworthiness of their counterparties on an on
going basis and require security, including prepayments and other forms of cash
collateral, when appropriate.
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Shareholders
ONEOK,
Inc.:
In our
opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, shareholders’ equity and comprehensive
income and cash flows present fairly, in all material respects, the financial
position of ONEOK, Inc. and its subsidiaries (the Company) at December 31, 2008 and
2007, and the results of their operations and their cash flows for each of the
two years in the period ended December 31, 2008, in conformity with
accounting principles generally accepted in the United States of
America. Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31,
2008, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company’s management is responsible for
these financial statements, for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in Management’s Report on Internal Control
over Financial Reporting appearing under Item 9A in the Company’s Form 10-K for the year ended
December 31, 2008. Our responsibility is to express opinions on these
financial statements and on the Company’s internal control over
financial reporting based on our integrated audits. We conducted our
audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan
and perform the audits to obtain reasonable assurance about whether the
financial statements are free of material misstatement and whether effective
internal control over financial reporting was maintained in all material
respects. Our audits of the financial statements included examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and significant
estimates made by management, and evaluating the overall financial statement
presentation. Our audit of internal control over financial reporting
included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and
evaluating the design and operating effectiveness of internal control based on
the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe
that our audits provide a reasonable basis for our opinions.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of
the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and
(iii) provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers
LLP
February
24, 2009
Tulsa,
Oklahoma
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Shareholders
ONEOK,
Inc.:
We have
audited the accompanying consolidated statement of income, cash flows, and
shareholders’ equity and comprehensive income of ONEOK, Inc. and subsidiaries as
of December 31, 2006. The consolidated financial statements are the
responsibility of the Company’s management. Our responsibility is to
express an opinion on these consolidated financial statements based on our
audit.
We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our
opinion, the consolidated financial statements referred to above present fairly,
in all material respects, the results of operations and cash flows of ONEOK,
Inc. and subsidiaries for the year ended December 31, 2006, in conformity with
U.S. generally accepted accounting principles.
As
discussed in Note A of Notes to the Consolidated Financial Statements, the
Company adopted the provisions of Statement of Financial Accounting Standards
(SFAS) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans,” Emerging Issues Task Force Issue 04-5, “Determining
Whether a General Partner, or General Partners as a Group Controls a Limited
Partnership or Similar Entity When the Limited Partners Have Certain Rights,”
and SFAS No. 123R, “Share-Based Payment.”
/s/ KPMG
LLP
Tulsa,
Oklahoma
February
28, 2007
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED STATEMENTS
OF INCOME
|
|
|
|
|
|
|
|
|
|
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
(Thousands
of dollars, except per share amounts) |
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$ |
16,157,433 |
|
|
$ |
13,477,414 |
|
|
$ |
11,920,326 |
|
Cost
of sales and fuel
|
|
|
14,221,906 |
|
|
|
11,667,306 |
|
|
|
10,198,342 |
|
Net
Margin
|
|
|
1,935,527 |
|
|
|
1,810,108 |
|
|
|
1,721,984 |
|
Operating
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
and maintenance
|
|
|
694,597 |
|
|
|
675,575 |
|
|
|
662,681 |
|
Depreciation
and amortization
|
|
|
243,927 |
|
|
|
227,964 |
|
|
|
235,543 |
|
General
taxes
|
|
|
82,315 |
|
|
|
85,935 |
|
|
|
78,086 |
|
Total
Operating Expenses
|
|
|
1,020,839 |
|
|
|
989,474 |
|
|
|
976,310 |
|
Gain
(Loss) on Sale of Assets
|
|
|
2,316 |
|
|
|
1,909 |
|
|
|
116,528 |
|
Operating
Income
|
|
|
917,004 |
|
|
|
822,543 |
|
|
|
862,202 |
|
Equity
earnings from investments (Note O)
|
|
|
101,432 |
|
|
|
89,908 |
|
|
|
95,883 |
|
Allowance
for equity funds used during construction
|
|
|
50,906 |
|
|
|
12,538 |
|
|
|
2,205 |
|
Other
income
|
|
|
16,838 |
|
|
|
21,932 |
|
|
|
26,030 |
|
Other
expense
|
|
|
(27,475 |
) |
|
|
(7,879 |
) |
|
|
(24,154 |
) |
Interest
expense
|
|
|
(264,167 |
) |
|
|
(256,325 |
) |
|
|
(239,725 |
) |
Income
before Minority Interests and Income Taxes
|
|
|
794,538 |
|
|
|
682,717 |
|
|
|
722,441 |
|
Minority
interests in income of consolidated subsidiaries
|
|
|
(288,558 |
) |
|
|
(193,199 |
) |
|
|
(222,000 |
) |
Income
taxes (Note L)
|
|
|
(194,071 |
) |
|
|
(184,597 |
) |
|
|
(193,764 |
) |
Income
from Continuing Operations
|
|
|
311,909 |
|
|
|
304,921 |
|
|
|
306,677 |
|
Gain
(Loss) from operations of discontinued components, net of
tax
|
|
|
- |
|
|
|
- |
|
|
|
(365 |
) |
Net
Income
|
|
$ |
311,909 |
|
|
$ |
304,921 |
|
|
$ |
306,312 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
Per Share of Common Stock (Note P)
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Earnings Per Share, Basic
|
|
$ |
2.99 |
|
|
$ |
2.84 |
|
|
$ |
2.74 |
|
Net
Earnings Per Share, Diluted
|
|
$ |
2.95 |
|
|
$ |
2.79 |
|
|
$ |
2.68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
Shares of Common Stock (Thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
104,369 |
|
|
|
107,346 |
|
|
|
112,006 |
|
Diluted
|
|
|
105,760 |
|
|
|
109,298 |
|
|
|
114,477 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
Declared Per Share of Common Stock
|
|
$ |
1.56 |
|
|
$ |
1.40 |
|
|
$ |
1.22 |
|
See
accompanying Notes to Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Assets
|
|
(Thousands
of dollars)
|
|
|
|
|
|
|
|
|
Current
Assets
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
510,058 |
|
|
$ |
19,105 |
|
Accounts
receivable, net
|
|
|
1,265,300 |
|
|
|
1,723,212 |
|
Gas
and natural gas liquids in storage
|
|
|
858,966 |
|
|
|
841,362 |
|
Commodity
exchanges and imbalances
|
|
|
56,248 |
|
|
|
82,938 |
|
Energy
marketing and risk management assets (Notes C and D)
|
|
|
362,808 |
|
|
|
143,941 |
|
Other
current assets
|
|
|
324,222 |
|
|
|
140,917 |
|
Total
Current Assets
|
|
|
3,377,602 |
|
|
|
2,951,475 |
|
|
|
|
|
|
|
|
|
|
Property,
Plant and Equipment
|
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
|
9,476,619 |
|
|
|
7,893,492 |
|
Accumulated
depreciation and amortization
|
|
|
2,212,850 |
|
|
|
2,048,311 |
|
Net
Property, Plant and Equipment (Note A)
|
|
|
7,263,769 |
|
|
|
5,845,181 |
|
|
|
|
|
|
|
|
|
|
Investments
and Other Assets
|
|
|
|
|
|
|
|
|
Goodwill
and intangible assets (Note E)
|
|
|
1,038,226 |
|
|
|
1,043,773 |
|
Energy
marketing and risk management assets (Notes C and D)
|
|
|
45,900 |
|
|
|
3,978 |
|
Investments
in unconsolidated affiliates (Note O)
|
|
|
755,492 |
|
|
|
756,260 |
|
Other
assets
|
|
|
645,073 |
|
|
|
461,367 |
|
Total
Investments and Other Assets
|
|
|
2,484,691 |
|
|
|
2,265,378 |
|
Total
Assets
|
|
$ |
13,126,062 |
|
|
$ |
11,062,034 |
|
See
accompanying Notes to Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Liabilities
and Shareholders’ Equity
|
|
(Thousands
of dollars)
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
|
|
|
|
Current
maturities of long-term debt (Note I)
|
|
$ |
118,195 |
|
|
$ |
420,479 |
|
Notes
payable
|
|
|
2,270,000 |
|
|
|
202,600 |
|
Accounts
payable
|
|
|
1,122,761 |
|
|
|
1,436,005 |
|
Commodity
exchanges and imbalances
|
|
|
188,030 |
|
|
|
252,095 |
|
Energy
marketing and risk management liabilities (Notes C and D)
|
|
|
175,006 |
|
|
|
133,903 |
|
Other
current liabilities
|
|
|
319,772 |
|
|
|
436,585 |
|
Total
Current Liabilities
|
|
|
4,193,764 |
|
|
|
2,881,667 |
|
|
|
|
|
|
|
|
|
|
Long-term
Debt, excluding current maturities (Note I)
|
|
|
4,112,581 |
|
|
|
4,215,046 |
|
|
|
|
|
|
|
|
|
|
Deferred
Credits and Other Liabilities
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
890,815 |
|
|
|
680,543 |
|
Energy
marketing and risk management liabilities (Notes C and D)
|
|
|
46,311 |
|
|
|
26,861 |
|
Other
deferred credits
|
|
|
715,052 |
|
|
|
486,645 |
|
Total
Deferred Credits and Other Liabilities
|
|
|
1,652,178 |
|
|
|
1,194,049 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note K)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority
Interests in Consolidated Subsidiaries
|
|
|
1,079,369 |
|
|
|
801,964 |
|
|
|
|
|
|
|
|
|
|
Shareholders’
Equity
|
|
|
|
|
|
|
|
|
Common
stock, $0.01 par value:
|
|
|
|
|
|
|
|
|
authorized
300,000,000 shares; issued 121,647,007 shares
|
|
|
|
|
|
|
|
|
and
outstanding 104,845,231 shares at December 31, 2008;
|
|
|
|
|
|
|
|
|
issued
121,115,217 shares and outstanding 103,987,476
|
|
|
|
|
|
|
|
|
shares
at December 31, 2007
|
|
|
1,216 |
|
|
|
1,211 |
|
Paid
in capital
|
|
|
1,301,153 |
|
|
|
1,273,800 |
|
Accumulated
other comprehensive loss (Note F)
|
|
|
(70,616 |
) |
|
|
(7,069 |
) |
Retained
earnings
|
|
|
1,553,033 |
|
|
|
1,411,492 |
|
Treasury
stock, at cost: 16,801,776 shares at December 31,
|
|
|
|
|
|
|
|
|
2008
and 17,127,741 shares at December 31, 2007
|
|
|
(696,616 |
) |
|
|
(710,126 |
) |
Total
Shareholders’ Equity
|
|
|
2,088,170 |
|
|
|
1,969,308 |
|
Total
Liabilities and Shareholders’ Equity
|
|
$ |
13,126,062 |
|
|
$ |
11,062,034 |
|
See
accompanying Notes to Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
This page
intentionally left blank.
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
Years
Ended December 31,
|
|
|
2008
|
|
2007
|
|
2006
|
|
Operating
Activities
|
(Thousands
of dollars)
|
|
Net
income
|
$ |
311,909 |
|
$ |
304,921 |
|
$ |
306,312 |
|
Depreciation
and amortization
|
|
243,927 |
|
|
227,964 |
|
|
235,543 |
|
Allowance
for equity funds used during construction
|
|
(50,906 |
) |
|
(12,538 |
) |
|
(2,205 |
) |
Gain
on sale of assets
|
|
(2,316 |
) |
|
(1,909 |
) |
|
(116,528 |
) |
Minority
interests in income of consolidated subsidiaries
|
|
288,558 |
|
|
193,199 |
|
|
222,000 |
|
Equity
earnings from investments
|
|
(101,432 |
) |
|
(89,908 |
) |
|
(95,883 |
) |
Distributions
received from unconsolidated affiliates
|
|
93,261 |
|
|
103,785 |
|
|
123,427 |
|
Deferred
income taxes
|
|
165,191 |
|
|
65,017 |
|
|
115,384 |
|
Stock-based
compensation expense
|
|
30,791 |
|
|
20,909 |
|
|
16,499 |
|
Allowance
for doubtful accounts
|
|
13,476 |
|
|
14,578 |
|
|
9,056 |
|
Inventory
adjustment, net
|
|
9,658 |
|
|
- |
|
|
- |
|
Investment
securities gains
|
|
(11,142 |
) |
|
- |
|
|
- |
|
Changes
in assets and liabilities (net of acquisition and disposition
effects):
|
|
|
|
|
|
|
|
|
|
Accounts
and notes receivable
|
|
433,859 |
|
|
(378,876 |
) |
|
649,415 |
|
Gas
and natural gas liquids in storage
|
|
(370,662 |
) |
|
88,937 |
|
|
(13,801 |
) |
Accounts
payable
|
|
(340,584 |
) |
|
343,144 |
|
|
(425,715 |
) |
Commodity
exchanges and imbalances, net
|
|
(37,375 |
) |
|
40,572 |
|
|
18,001 |
|
Unrecovered
purchased gas costs
|
|
(35,790 |
) |
|
9,530 |
|
|
(73,534 |
) |
Accrued
interest
|
|
16,002 |
|
|
9,001 |
|
|
25,329 |
|
Energy
marketing and risk management assets and liabilities
|
|
60,846 |
|
|
41,649 |
|
|
(63,040 |
) |
Fair
value of firm commitments
|
|
505 |
|
|
5,631 |
|
|
190,795 |
|
Pension
and postretirement benefit plans
|
|
(83,254 |
) |
|
28,573 |
|
|
(14,496 |
) |
Other
assets and liabilities
|
|
(158,845 |
) |
|
15,481 |
|
|
(233,283 |
) |
Cash
Provided by Operating Activities
|
|
475,677 |
|
|
1,029,660 |
|
|
873,276 |
|
Investing
Activities
|
|
|
|
|
|
|
|
|
|
Changes
in investments in unconsolidated affiliates
|
|
3,963 |
|
|
(3,668 |
) |
|
(6,608 |
) |
Acquisitions
|
|
2,450 |
|
|
(299,560 |
) |
|
(148,892 |
) |
Capital
expenditures (less allowance for equity funds used during
construction)
|
|
(1,473,136 |
) |
|
(883,703 |
) |
|
(376,306 |
) |
Proceeds
from sale of discontinued component
|
|
- |
|
|
- |
|
|
53,000 |
|
Proceeds
from sale of assets
|
|
2,630 |
|
|
4,022 |
|
|
298,964 |
|
Proceeds
from insurance
|
|
9,792 |
|
|
- |
|
|
- |
|
Changes
in short-term investments
|
|
- |
|
|
31,125 |
|
|
(31,125 |
) |
Increase
in cash and cash equivalents attributable to previously unconsolidated
subsidiaries
|
|
- |
|
|
- |
|
|
1,334 |
|
Decrease
in cash and cash equivalents attributable to previously consolidated
subsidiaries
|
|
- |
|
|
- |
|
|
(22,039 |
) |
Other
investing activities
|
|
- |
|
|
- |
|
|
(5,565 |
) |
Cash
Used in Investing Activities
|
|
(1,454,301 |
) |
|
(1,151,784 |
) |
|
(237,237 |
) |
Financing
Activities
|
|
|
|
|
|
|
|
|
|
Borrowing
(repayment) of notes payable, net
|
|
1,197,400 |
|
|
196,600 |
|
|
(842,000 |
) |
Borrowing
(repayment) of notes payable with maturities over 90 days
|
|
870,000 |
|
|
- |
|
|
(900,000 |
) |
Issuance
of debt, net of issuance costs
|
|
- |
|
|
598,146 |
|
|
1,397,328 |
|
Long-term
debt financing costs
|
|
- |
|
|
(5,805 |
) |
|
(12,003 |
) |
Payment
of debt
|
|
(416,040 |
) |
|
(13,588 |
) |
|
(44,359 |
) |
Equity
unit conversion
|
|
- |
|
|
- |
|
|
402,448 |
|
Repurchase
of common stock
|
|
(29 |
) |
|
(390,213 |
) |
|
(281,444 |
) |
Issuance
of common stock
|
|
16,495 |
|
|
20,730 |
|
|
10,829 |
|
Issuance
of common units, net of discounts
|
|
146,969 |
|
|
- |
|
|
- |
|
Dividends
paid
|
|
(162,785 |
) |
|
(150,188 |
) |
|
(135,451 |
) |
Distributions
to minority interests
|
|
(201,658 |
) |
|
(182,891 |
) |
|
(165,283 |
) |
Other
financing activities
|
|
19,225 |
|
|
170 |
|
|
(48,841 |
) |
Cash
Provided by (Used in) Financing Activities
|
|
1,469,577 |
|
|
72,961 |
|
|
(618,776 |
) |
Change
in Cash and Cash Equivalents
|
|
490,953 |
|
|
(49,163 |
) |
|
17,263 |
|
Cash
and Cash Equivalents at Beginning of Period
|
|
19,105 |
|
|
68,268 |
|
|
7,915 |
|
Effect
of Accounting Change on Cash and Cash Equivalents
|
|
- |
|
|
- |
|
|
43,090 |
|
Cash
and Cash Equivalents at End of Period
|
$ |
510,058 |
|
$ |
19,105 |
|
$ |
68,268 |
|
Supplemental
Cash Flow Information:
|
|
|
|
|
|
|
|
|
|
Cash
Paid for Interest
|
$ |
237,577 |
|
$ |
253,678 |
|
$ |
225,998 |
|
Cash
Paid for Taxes
|
$ |
82,965 |
|
$ |
57,281 |
|
$ |
262,504 |
|
See
accompanying Notes to Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
|
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE
INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock
|
|
|
Common
|
|
|
Paid-in
|
|
|
Unearned
|
|
|
|
Issued
|
|
|
Stock
|
|
|
Capital
|
|
|
Compensation
|
|
|
|
(Shares)
|
|
|
(Thousands
of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2005
|
|
|
107,973,436 |
|
|
$ |
1,080 |
|
|
$ |
1,044,283 |
|
|
$ |
(105 |
) |
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Other
comprehensive income (loss)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adoption
of Statement 158
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Equity
unit conversion
|
|
|
11,208,998 |
|
|
|
112 |
|
|
|
177,572 |
|
|
|
- |
|
Repurchase
of common stock
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Common
stock issued
|
|
|
1,151,474 |
|
|
|
11 |
|
|
|
36,862 |
|
|
|
158 |
|
Common
stock dividends -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.22
per share
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(53 |
) |
December
31, 2006
|
|
|
120,333,908 |
|
|
|
1,203 |
|
|
|
1,258,717 |
|
|
|
- |
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Other
comprehensive income (loss)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase
of common stock
|
|
|
- |
|
|
|
- |
|
|
|
(11,103 |
) |
|
|
- |
|
Common
stock issued
|
|
|
781,309 |
|
|
|
8 |
|
|
|
26,186 |
|
|
|
- |
|
Common
stock dividends -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.40
per share
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
December
31, 2007
|
|
|
121,115,217 |
|
|
|
1,211 |
|
|
|
1,273,800 |
|
|
|
- |
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Other
comprehensive income (loss)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repurchase
of common stock
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Common
stock issued
|
|
|
531,790 |
|
|
|
5 |
|
|
|
27,353 |
|
|
|
- |
|
Common
stock dividends -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.56
per share
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Change
in measurement date for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
employee
benefit plans
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
December
31, 2008
|
|
|
121,647,007 |
|
|
$ |
1,216 |
|
|
$ |
1,301,153 |
|
|
$ |
- |
|
See
accompanying Notes to Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
|
ONEOK,
Inc. and Subsidiaries
|
|
|
|
|
|
|
|
|
|
|
|
|
CONSOLIDATED
STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE
INCOME
|
|
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive
|
|
|
Retained
|
|
|
Treasury
|
|
|
|
|
|
|
Income
(Loss)
|
|
|
Earnings
|
|
|
Stock
|
|
|
Total
|
|
|
|
(Thousands
of dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2005
|
|
$ |
(56,991 |
) |
|
$ |
1,085,845 |
|
|
$ |
(279,355 |
) |
|
$ |
1,794,757 |
|
Net
income
|
|
|
- |
|
|
|
306,312 |
|
|
|
- |
|
|
|
306,312 |
|
Other
comprehensive income (loss)
|
|
|
63,878 |
|
|
|
- |
|
|
|
- |
|
|
|
63,878 |
|
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
370,190 |
|
Adoption
of Statement 158
|
|
|
32,645 |
|
|
|
- |
|
|
|
- |
|
|
|
32,645 |
|
Equity
unit conversion
|
|
|
- |
|
|
|
- |
|
|
|
224,764 |
|
|
|
402,448 |
|
Repurchase
of common stock
|
|
|
- |
|
|
|
- |
|
|
|
(285,662 |
) |
|
|
(285,662 |
) |
Common
Stock issued
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
37,031 |
|
Common
stock dividends -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.22
per share
|
|
|
- |
|
|
|
(135,398 |
) |
|
|
- |
|
|
|
(135,451 |
) |
December
31, 2006
|
|
|
39,532 |
|
|
|
1,256,759 |
|
|
|
(340,253 |
) |
|
|
2,215,958 |
|
Net
income
|
|
|
- |
|
|
|
304,921 |
|
|
|
- |
|
|
|
304,921 |
|
Other
comprehensive income (loss)
|
|
|
(46,601 |
) |
|
|
- |
|
|
|
- |
|
|
|
(46,601 |
) |
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
258,320 |
|
Repurchase
of common stock
|
|
|
- |
|
|
|
- |
|
|
|
(379,110 |
) |
|
|
(390,213 |
) |
Common
stock issued
|
|
|
- |
|
|
|
- |
|
|
|
9,237 |
|
|
|
35,431 |
|
Common
stock dividends -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.40
per share
|
|
|
- |
|
|
|
(150,188 |
) |
|
|
- |
|
|
|
(150,188 |
) |
December
31, 2007
|
|
|
(7,069 |
) |
|
|
1,411,492 |
|
|
|
(710,126 |
) |
|
|
1,969,308 |
|
Net
income
|
|
|
- |
|
|
|
311,909 |
|
|
|
- |
|
|
|
311,909 |
|
Other
comprehensive income (loss)
|
|
|
(63,547 |
) |
|
|
- |
|
|
|
- |
|
|
|
(63,547 |
) |
Total
comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
248,362 |
|
Repurchase
of common stock
|
|
|
- |
|
|
|
- |
|
|
|
(29 |
) |
|
|
(29 |
) |
Common
stock issued
|
|
|
- |
|
|
|
- |
|
|
|
13,539 |
|
|
|
40,897 |
|
Common
stock dividends -
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.56
per share
|
|
|
- |
|
|
|
(162,785 |
) |
|
|
- |
|
|
|
(162,785 |
) |
Change
in measurement date for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
employee
benefit plans
|
|
|
- |
|
|
|
(7,583 |
) |
|
|
|
|
|
|
(7,583 |
) |
December
31, 2008
|
|
$ |
(70,616 |
) |
|
$ |
1,553,033 |
|
|
$ |
(696,616 |
) |
|
$ |
2,088,170 |
|
ONEOK,
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
A. SUMMARY
OF ACCOUNTING POLICIES
Organization and Nature of
Operations - We are a
diversified energy company and successor to the company founded in 1906 known as
Oklahoma Natural Gas Company. Our common stock is listed on the NYSE
under the trading symbol “OKE.” We are the sole general partner and
own 47.7 percent of ONEOK Partners, L.P. (NYSE: OKS), one of the largest
publicly traded master limited partnerships.
We have
divided our operations into four reportable business segments based on
similarities in economic characteristics, products and services, types of
customers, methods of distribution and regulatory environment. These
segments are as follows:
Our ONEOK
Partners segment is engaged in the gathering and processing of unprocessed
natural gas and fractionation of NGLs, primarily in the Mid-Continent and Rocky
Mountain regions covering Oklahoma, Kansas, Montana, North Dakota and
Wyoming. These operations include the gathering of unprocessed
natural gas produced from crude oil and natural gas wells. Through
gathering systems, unprocessed natural gas is aggregated and treated or
processed for removal of water vapor, solids and other contaminants, and to
extract NGLs in order to provide marketable natural gas, commonly referred to as
residue gas. 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 stream is then separated by a
distillation process, referred to as fractionation, into marketable product
components such as ethane, ethane/propane (E/P), propane, iso-butane, normal
butane and natural gasoline (collectively, NGL products). These NGL
products can then be stored, transported and marketed to a diverse customer base
of end-users.
ONEOK
Partners also gathers, treats, fractionates, transports and stores
NGLs. ONEOK Partners’ natural gas liquids gathering pipelines deliver
unfractionated NGLs gathered from natural gas processing plants located in
Oklahoma, Kansas, the Texas panhandle and the Rocky Mountain region to
fractionators it owns in Oklahoma, Kansas and Texas. The NGLs are
then separated through the fractionation process into the individual NGL
products that realize the greater economic value of the NGL
components. The individual NGL products are then stored or
distributed to petrochemical manufacturers, heating fuel users, refineries and
propane distributors through ONEOK Partners’ distribution pipelines that move
NGL products from Oklahoma and Kansas to the market centers in Conway, Kansas,
and Mont Belvieu, Texas, as well as the Midwest markets near Chicago,
Illinois.
ONEOK
Partners operates interstate and intrastate natural gas transmission pipelines,
natural gas storage facilities and non-processable natural gas gathering
facilities. ONEOK Partners’ interstate assets transport natural gas
through FERC-regulated interstate natural gas pipelines that access supply from
Canada, and the Mid-Continent, Rocky Mountain and Gulf Coast
regions.
ONEOK
Partners’ intrastate natural gas pipeline assets in Oklahoma have access to the
major natural gas producing areas and transport natural gas throughout the
state. ONEOK Partners also has access to the major natural gas
producing area in south central Kansas. In Texas, its 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 east to the
Houston Ship Channel market, north into the Mid-Continent market and west to the
California market. ONEOK Partners owns or leases storage capacity in
underground natural gas storage facilities in Oklahoma, Kansas and
Texas. ONEOK Partners’ natural gas pipelines primarily serve LDCs,
large industrial companies, municipalities, irrigation customers, power
generation facilities and marketing companies.
Our
Distribution segment provides natural gas distribution services to more than two
million customers in Oklahoma, Kansas and Texas through Oklahoma Natural Gas,
Kansas Gas Service and Texas Gas Service, respectively, each a division of
ONEOK. We serve residential, commercial, industrial and
transportation customers in all three states. In addition, our
distribution companies in Oklahoma and Kansas serve wholesale customers, and in
Texas we serve public authority customers, such as cities, governmental agencies
and schools.
Our
Energy Services segment’s primary focus is to create value for our customers by
delivering physical natural gas products and risk management services through
our network of contracted transportation and storage capacity and natural gas
supply. These services include meeting our customers’ baseload, swing
and peaking natural gas commodity requirements on a year-round
basis. To provide these bundled services, we lease storage and
transportation capacity. Our contracted storage and transportation
capacity connects major supply and demand centers throughout the United States
and into Canada. With these contracted assets, our business
strategies include identifying, developing and delivering specialized services
and products valued by our customers, which are primarily LDCs, electric
utilities, and commercial and industrial end users. Our storage and
transportation capacity allows us opportunities to optimize value through our
application of market knowledge and risk management skills.
Critical
Accounting Policies
The
following is a summary of our most critical accounting policies, 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.
Fair Value Measurements - General - In
September 2006, the FASB issued Statement 157, “Fair Value Measurements” that
establishes a framework for measuring fair value and requires additional
disclosures about fair value measurements. Beginning January 1, 2008,
we partially applied Statement 157 as allowed by FASB Staff Position (FSP)
157-2, “Effective Date of FASB Statement No. 157” that delayed the effective
date of Statement 157 for nonrecurring fair value measurements associated with
our nonfinancial assets and liabilities. As of January 1, 2008, we
applied the provisions of Statement 157 to our recurring fair value
measurements, and the impact was not material upon adoption. As of
January 1, 2009, we have applied the provisions of Statement 157 to our
nonrecurring fair value measurements associated with our nonfinancial assets and
liabilities, and the impact was not material. FSP 157-3, “Determining
the Fair Value of a Financial Asset When the Market for That Asset Is Not
Active,” which clarified the application of Statement 157 in inactive markets,
was issued in October 2008 and was effective for our September 30, 2008,
unaudited consolidated financial statements. FSP 157-3 did not have a
material impact on our consolidated financial statements.
In
February 2007, the FASB issued Statement 159, “The Fair Value Option for
Financial Assets and Financial Liabilities” that allows companies to elect to
measure specified financial assets and liabilities, firm commitments, and
nonfinancial warranty and insurance contracts at fair value on a
contract-by-contract basis, with changes in fair value recognized in earnings
each reporting period. At January 1, 2008, we did not elect the fair
value option under Statement 159, and therefore there was no impact on our
consolidated financial statements.
Determining Fair
Value - Statement 157 defines fair value as the price that would be
received to sell an asset or transfer a liability in an orderly transaction
between market participants at the measurement date. We use the
market and income approaches to determine the fair value of our assets and
liabilities and consider the markets in which the transactions are
executed. While many of the contracts in our portfolio are executed
in liquid markets where price transparency exists, some contracts are executed
in markets for which market prices may exist but the market may be relatively
inactive. This results in limited price transparency that requires
management’s judgment and assumptions to estimate fair values. Inputs
into our fair value estimates include commodity exchange prices,
over-the-counter quotes, volatility, historical correlations of pricing data and
LIBOR and other liquid money market instrument rates. We also utilize
internally developed basis curves that incorporate observable and unobservable
market data. We validate our valuation inputs with third-party
information and settlement prices from other sources, where
available. In addition, as prescribed by the income approach, we
compute the fair value of our derivative portfolio by discounting the projected
future cash flows from our derivative assets and liabilities to present
value. The interest rate yields used to calculate the present value
discount factors are derived from LIBOR, Eurodollar futures and Treasury
swaps. The projected cash flows are then multiplied by the
appropriate discount factors to determine the present value or fair value of our
derivative instruments. We also take into consideration the potential
impact on market prices of liquidating positions in an orderly manner over a
reasonable period of time under current market conditions. Finally,
we consider credit risk of our counterparties on the fair value of our
derivative assets, as well as our own credit risk for derivative liabilities,
using default probabilities and recovery rates, net of collateral. We
also take into consideration current market data in our evaluation when
available, such as bond prices and yields and credit default
swaps. Although we use our best estimates to determine the fair value
of the derivative contracts we have executed, the ultimate market prices
realized could differ from our estimates, and the differences could be
material.
Fair Value Hierarchy
- Statement 157 establishes the fair value hierarchy that prioritizes inputs to
valuation techniques based on observable and unobservable data and categorizes
the inputs into three levels, with the highest priority given to Level 1 and the
lowest priority given to Level 3. The levels are described
below.
·
|
Level
1 - Unadjusted quoted prices in active markets for identical assets or
liabilities.
|
·
|
Level
2 - Significant observable pricing inputs other than quoted prices
included within Level 1 that are either directly or indirectly observable
as of the reporting date. Essentially, this represents inputs
that are derived principally from or corroborated by observable market
data.
|
·
|
Level
3 - Generally unobservable inputs, which are developed based on the best
information available and may include our own internal
data.
|
Determining
the appropriate classification of our fair value measurements within the fair
value hierarchy requires management’s judgment regarding the degree to which
market data is observable or corroborated by observable market
data.
See Note
C for more discussion of our fair value measurements.
Derivatives, Accounting for
Financially Settled Transactions and Risk Management Activities - We
engage in wholesale energy marketing, retail marketing, trading and risk
management activities. We account for derivative instruments utilized
in connection with these activities and services in accordance with Statement
133, “Accounting for Derivative Instruments and Hedging Activities,” as
amended.
Under
Statement 133, entities are required to record all derivative instruments at
fair value, with the exception of normal purchases and normal sales that are
expected to result in physical delivery. See previous discussion in
“Fair Value Measurements” for additional information. Market value
changes result in a change in the fair value of our derivative
instruments. The accounting for changes in the fair value of a
derivative instrument depends on whether it has been designated and qualifies as
part of a hedging relationship and, if so, the nature of the risk being hedged
and how we will determine if the hedging instrument is effective. If
the derivative instrument does not qualify or is not designated as part of a
hedging relationship, then we account for changes in fair value of the
derivative in earnings as they occur. Commodity price volatility may
have a significant impact on the gain or loss in a given period.
To reduce
our exposure to fluctuations in natural gas, NGLs and condensate prices, we
periodically enter into futures, forwards, options or swap transactions in order
to hedge anticipated purchases and sales of natural gas, NGLs, condensate and
fuel requirements. Interest-rate swaps are also used to manage
interest-rate risk. Under certain conditions, we designate these
derivative instruments as a hedge of exposure to changes in fair values or cash
flows. For hedges of exposure to changes in cash flow, the effective
portion of the gain or loss on the derivative instrument is reported initially
as a component of accumulated other comprehensive income (loss) and is
subsequently recorded to earnings when the forecasted transaction affects
earnings. Any ineffectiveness of designated hedges is reported in
earnings during the period the ineffectiveness occurs. For hedges of
exposure to changes in fair value, the gain or loss on the derivative instrument
is recognized in earnings during the period of change, together with the
offsetting gain or loss on the hedged item attributable to the risk being
hedged.
Upon
election, many of our purchase and sale agreements that otherwise would be
required to follow derivative accounting qualify as normal purchases and normal
sales under Statement 133 and are therefore exempt from fair value accounting
treatment.
The
presentation of settled derivative instruments on either a gross or net basis in
our Consolidated Statements of Income is dependent on a number of factors,
including whether the derivative instrument (i) is held for trading purposes;
(ii) is financially settled; (iii) results in physical delivery or services
rendered; and (iv) qualifies for the normal purchase or sale exception as
defined in Statement 133. In accordance with EITF 03-11, “Reporting
Realized Gains and Losses on Derivative Instruments That Are Subject to FASB
Statement No. 133 and not ‘Held for Trading’ as Defined in EITF Issue No. 02-3,”
EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” and
Statement 133, we report settled derivative instruments as follows:
·
|
all
financially settled derivative contracts are reported on a net
basis;
|
·
|
derivative
instruments considered held for trading purposes that result in physical
delivery are reported on a net
basis;
|
·
|
derivative
instruments not considered held for trading purposes that result in
physical delivery or services rendered are reported on a gross basis;
and
|
·
|
derivatives
that qualify for the normal purchase or sale exception as defined in
Statement 133 are reported on a gross
basis.
|
We apply
the indicators in EITF 99-19 to determine the appropriate accounting treatment
for non-derivative contracts that result in physical delivery.
See Note
D for more discussion of derivatives and risk management
activities.
Impairment of Long-Lived Assets,
Goodwill and Intangible Assets - We assess our long-lived assets for
impairment based on Statement 144, “Accounting for the Impairment or Disposal of
Long-Lived Assets.” A long-lived asset is tested for impairment
whenever events or changes in circumstances indicate that its carrying amount
may exceed its fair value. Fair values are based on the sum of the
undiscounted future cash flows expected to result from the use and eventual
disposition of the assets.
We assess
our goodwill and indefinite-lived intangible assets for impairment at least
annually based on Statement 142, “Goodwill and Other Intangible
Assets.” There were no impairment charges resulting from our July 1,
2008, impairment test. As a result of recent events in the financial
markets and current economic conditions, we performed a review and determined
that interim testing of goodwill as of December 31, 2008, was not
necessary. As a 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. If the fair value is less than the book value, an
impairment is indicated, and we must perform a second test to measure the amount
of the impairment. In the second test, we calculate the implied fair
value of the goodwill by deducting the fair value of all tangible and intangible
net assets of the reporting unit from the fair value determined in step one of
the assessment. If the carrying value of the goodwill exceeds the
implied fair value of the goodwill, we will record an impairment
charge.
We use
two generally accepted valuation approaches, an income approach and a market
approach, to estimate the fair value of a reporting unit. Under the
income approach, we use anticipated cash flows over a three-year period plus a
terminal value and discount these amounts to their present value using
appropriate rates of return. Under the market approach, we apply
multiples to forecasted EBITDA amounts. The multiples used are
consistent with historical asset transactions, and the EBITDA amounts are based
on average EBITDA for a reporting unit over a three-year forecasted
period. See Note E for more discussion of goodwill.
Intangible
assets with a finite useful life are amortized over their estimated useful life,
while intangible assets with an indefinite useful life are not
amortized. All intangible assets are subject to impairment
testing. We had $435.4 million of intangible assets recorded on our
Consolidated Balance Sheet as of December 31, 2008, of which $279.8 million in
our ONEOK Partners segment is being amortized over an aggregate weighted-average
period of 40 years, while the remaining balance has an indefinite
life.
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.
For the
investments we account for under the equity method, the premium or excess cost
over underlying fair value of net assets is referred to as equity method
goodwill and under Statement 142, is not subject to amortization but rather to
impairment testing pursuant to APB Opinion No. 18, “The Equity Method of
Accounting for Investments in Common Stock.” The impairment test
under APB Opinion No. 18 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
reevaluate the amount at which we carry the excess of cost over fair value of
net assets accounted for under the equity method to determine whether current
events or circumstances warrant adjustments to our carrying value in accordance
with APB Opinion No. 18.
Pension and Postretirement Employee
Benefits - We have defined benefit retirement plans covering certain
full-time employees. We sponsor welfare plans that provide
postretirement medical and life insurance benefits to certain employees who
retire with at least five years of service. Our actuarial consultant
calculates the expense and liability related to these plans and uses statistical
and other factors that attempt to anticipate future events. These
factors include assumptions about the discount rate, expected return on plan
assets, rate of future compensation increases, age and employment
periods. In determining the projected benefit obligations and costs,
assumptions can change from period to period and result in material changes in
the costs and liabilities we recognize. See Note J for more
discussion of pension and postretirement employee benefits.
In
September 2006, the FASB issued Statement 158, “Employers’ Accounting for
Defined Benefit Pension and Other Postretirement Plans,” which required us to
record a balance sheet liability equal to the difference between our benefit
obligations and plan assets. Statement 158 also required us to change
our measurement date from September 30 to December 31. Statement 158
was effective for our year ended December 31, 2006, except for the measurement
date change, which was effective for our year ending December 31,
2008. We determined our net periodic benefit cost for the period
October 1, 2007, through December 31, 2008, based on a measurement date of
September 30, 2007. The net periodic benefit cost for the period of
October 1, 2007, through December 31, 2007, was reflected as an adjustment to
retained earnings as of December 31, 2008. The impact of this
adjustment was a $7.6 million reduction to retained earnings, net of
taxes.
Contingencies - Our accounting
for contingencies covers a variety of business activities, including
contingencies for legal and environmental exposures. We accrue these
contingencies when our assessments indicate that it is probable that a liability
has been incurred or an asset will not be recovered and an amount can be
reasonably estimated in accordance with Statement 5, “Accounting for
Contingencies.” We base our estimates on currently available facts
and our estimates of the ultimate outcome or resolution. Accruals for
estimated losses from environmental remediation obligations generally are
recognized no later than completion of the remediation feasibility
study. Recoveries of environmental remediation costs from other
parties are recorded as assets when their receipt is deemed
probable. Actual results may differ from our estimates resulting in
an impact, positive or negative, on earnings. See Note K for
additional discussion of contingencies.
Significant
Accounting Policies
Consolidation - Our
consolidated financial statements include the accounts of ONEOK and our
subsidiaries over which we have control. We have recorded minority
interests in consolidated subsidiaries on our Consolidated Balance Sheets to
recognize the percent of ONEOK Partners that we do not own. We
reflected our percent share of ONEOK Partners’ accumulated other comprehensive
income (loss) in our consolidated accumulated other comprehensive income
(loss). The remaining percent is reflected as an adjustment to
minority interests in consolidated subsidiaries. All significant
intercompany balances and transactions have been eliminated in
consolidation. Investments in affiliates are accounted for using the
equity method if we have the ability to exercise significant influence over
operating and financial policies of our investee; conversely, if we do not have
the ability to exercise significant influence, then we use the cost
method. Impairment of equity and cost method investments is recorded
when the impairments are other than temporary.
Use of 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. Items
that may be estimated include, but are not limited to, the economic useful life
of assets, fair value of assets and liabilities, obligations under employee
benefit plans, provisions for uncollectible accounts receivable, unbilled
revenues for natural gas delivered but for which meters have not been read, gas
purchased expense for natural gas purchased but for which no invoice has been
received, provision for income taxes, including any deferred tax valuation
allowances, the results of litigation and various other recorded or disclosed
amounts.
We
evaluate these estimates on an ongoing basis using historical experience,
consultation with experts and other methods we consider reasonable based on the
particular circumstances. Nevertheless, actual results may differ
significantly from the estimates. Any effects on our financial
position or results of operations from revisions to these estimates are recorded
in the period when the facts that give rise to the revision become
known.
Cash and Cash Equivalents -
Cash equivalents consist of highly liquid investments, which are readily
convertible into cash and have original maturities of three months or
less.
Accounts Receivable, net -
Accounts receivable represent valid claims against non-affiliated customers for
products sold or services rendered, net of allowances for doubtful
accounts. We assess the credit worthiness of our counterparties on an
ongoing basis and require security, including prepayments and other forms of
cash collateral, when appropriate. Outstanding customer receivables
are regularly reviewed for possible non-payment indicators and allowances for
doubtful accounts are recorded based upon management’s estimate of
collectibility at each balance sheet date.
Inventories - Our current
natural gas and NGLs in storage are determined using the lower of
weighted-average cost or market method. Noncurrent natural gas and
NGLs are classified as property and valued at cost. Materials and
supplies are valued at average cost.
Through
December 31, 2007, the cost of current natural gas in storage for Oklahoma
Natural Gas was determined under the last-in, first-out (LIFO)
methodology. The estimated replacement cost of current natural gas in
storage was $72.4 million at December 31, 2007, compared with its value under
the LIFO method of $85.4 million at December 31, 2007. As of January
1, 2008, Oklahoma Natural Gas was required to change from LIFO to the
weighted-average cost methodology based on a change in state law. The
impact of this change on our consolidated financial statements was immaterial,
as the actual cost of gas is recovered from our rate payers through our
purchased gas recovery mechanism.
Natural Gas Imbalances and Commodity
Exchanges - Natural gas imbalances
and NGL exchanges are valued at market or their contractually stipulated
rate. Imbalances and NGL exchanges are settled in cash or made up
in-kind, subject to the terms of the pipelines’ tariffs or by
agreement.
EITF
Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same
Counterparty” defines when a purchase and a sale of inventory with the same
party that operates in the same line of business should be considered a single
nonmonetary transaction. EITF 04-13 was effective for new
arrangements that a company enters into in periods beginning after March 15,
2006. We reviewed the applicability of EITF 04-13 to our operations
and determined that it did not have a material impact on our financial position
or results of operations.
Property, Plant and Equipment
- The following table sets forth our property, plant and equipment by segment,
for the periods presented.
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands
of dollars)
|
|
Non-Regulated
|
|
|
|
|
|
|
ONEOK
Partners
|
|
$ |
2,465,369 |
|
|
$ |
2,112,394 |
|
Energy
Services
|
|
|
7,907 |
|
|
|
7,845 |
|
Other
|
|
|
225,479 |
|
|
|
177,356 |
|
Regulated
|
|
|
|
|
|
|
|
|
ONEOK
Partners
|
|
|
3,343,310 |
|
|
|
2,323,977 |
|
Distribution
|
|
|
3,434,554 |
|
|
|
3,271,920 |
|
Property,
plant and equipment
|
|
|
9,476,619 |
|
|
|
7,893,492 |
|
Accumulated
depreciation and amortization
|
|
|
2,212,850 |
|
|
|
2,048,311 |
|
Net
property, plant and equipment
|
|
$ |
7,263,769 |
|
|
$ |
5,845,181 |
|
Our
properties are stated at cost which includes AFUDC. Generally, the
cost of regulated property retired or sold, plus removal costs, less salvage, is
charged to accumulated depreciation. Gains and losses from sales or
transfers of non-regulated properties or an entire operating unit or system of
our regulated properties are recognized in income. Maintenance and
repairs are charged directly to expense.
The
interest portion of AFUDC represents the cost of borrowed funds used to finance
construction activities. We capitalize interest expense during the
construction or upgrade of qualifying assets. Interest expense
capitalized in 2008, 2007 and 2006 was $39.9 million, $15.4 million and $2.0
million, respectively. Capitalized interest is recorded as a
reduction to interest expense. The equity portion of AFUDC represents
the capitalization of the estimated average cost of equity used during the
construction of major projects and is recorded in the cost of our regulated
properties and as a credit to the allowance for equity funds used during
construction.
Our
properties are depreciated using the straight-line method over their estimated
useful lives. Generally, we apply composite depreciation rates to
functional groups of property having similar economic
circumstances. We periodically conduct depreciation studies to assess
the economic lives of our assets. For our regulated assets, these
deprecation studies are completed as a part of our rate proceedings, and the
changes in economic lives, if applicable, are implemented prospectively when the
new rates are billed. For our non-regulated assets, if it is determined
that the estimated economic life changes, then the changes are made
prospectively. Changes in the estimated economic lives of our property,
plant and equipment could have a material effect on our financial position or
result of operations.
The
average depreciation rates for our regulated property are set forth in the
following table for the periods indicated.
|
|
Years
Ended December 31,
|
|
Regulated
Property
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
ONEOK
Partners
|
|
|
2.0%
- 2.4 |
% |
|
|
2.4%
- 2.5 |
% |
|
|
2.4%
- 2.6 |
% |
Distribution
|
|
|
2.7%
- 3.0 |
% |
|
|
2.7%
- 3.0 |
% |
|
|
2.7%
- 3.3 |
% |
ONEOK
Partners’ average depreciation rates for its regulated property decreased in
2008, compared with 2007, due to placing newly constructed natural gas liquids
pipeline assets with longer economic lives in service.
Property,
plant and equipment on our Consolidated Balance Sheets includes construction
work in process for capital projects that have not yet been put in service and
therefore are not being depreciated. The following table sets forth
our construction work in process, by segment, for the periods
presented.
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
(Millions
of dollars)
|
ONEOK
Partners
|
|
$ |
810.0 |
|
|
$ |
859.8 |
|
Distribution
|
|
|
57.0 |
|
|
|
51.3 |
|
Other
|
|
|
11.0 |
|
|
|
7.1 |
|
Total
construction work in process
|
|
$ |
878.0 |
|
|
$ |
918.2 |
|
Assets
are transferred out of construction work in process when they are substantially
complete and ready for their intended use, in accordance with Statement 34,
“Capitalization of Interest Cost.”
Revenue Recognition - Our ONEOK Partners
segment includes natural gas gathering and processing, natural gas liquids
gathering and fractionation, natural gas pipelines, and natural gas liquids
pipelines operations. ONEOK Partners’ natural gas gathering and
processing operations record revenue when gas is processed in or transported
through company facilities. ONEOK Partners’ natural gas liquids
gathering and fractionation operations record revenues based upon contracted
services and actual volumes exchanged or stored under service agreements in the
month services are provided. Revenue for ONEOK Partners’ natural gas
pipelines and natural gas liquids pipelines operations is recognized based upon
contracted capacity and contracted volumes transported and stored under service
agreements in the period services are provided.
Our
Distribution segment’s major industrial and commercial natural gas distribution
customers are invoiced as of the end of each month. All natural gas
residential distribution customers and some commercial customers are invoiced on
a cyclical basis throughout the month, and we accrue unbilled revenues at the
end of each month.
Our
Energy Services segment’s wholesale customers are invoiced as of the end of each
month based on physical sales. Retail customers are invoiced on a cyclical
basis throughout the month, and we accrue unbilled revenues at the end of each
month. Demand payments received for requirements contracts are
recognized in the period in which the service is provided. Our
fixed-price physical sales are accounted for as derivatives and are recorded at
fair value. See Note D “Accounting Treatment” for additional
information.
Income Taxes - Income taxes
are accounted for using the provisions of Statement 109, “Accounting for Income
Taxes.” Deferred income taxes are provided for the difference between
the financial statement and income tax basis of assets and liabilities and carry
forward items, based on income tax laws and rates existing at the time the
temporary differences are expected to reverse. The effect on deferred
taxes of a change in tax rates is deferred and amortized for operations
regulated by the OCC, KCC, RRC and various municipalities in
Texas. For all other operations, the effect is recognized in income
in the period that includes the enactment date. We continue to
amortize previously deferred investment tax credits for ratemaking purposes over
the period prescribed by the OCC, KCC, RRC and various municipalities in
Texas.
In June
2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes - An
Interpretation of FASB Statement No. 109,” which was effective for our year
beginning January 1, 2007. This interpretation was issued to clarify
the accounting for uncertainty in income taxes recognized in the financial
statements by prescribing a recognition threshold and measurement attribute for
the financial statement recognition and measurement of a tax position taken or
expected to be taken in a tax return. FIN 48 requires the recognition
of penalties and interest on any unrecognized tax benefits. Our
policy is to
reflect
penalties and interest as part of income tax expense as they become
applicable. The adoption of FIN 48 had an immaterial impact on our
consolidated financial statements, and the impact for 2008 and 2007 was not
material.
We file
numerous consolidated and separate income tax returns in the United States
federal jurisdiction and in many state jurisdictions. We also file
returns in Canada. No extensions of statute of limitations have been
requested or granted. Our 2007 and 2006 United States federal income
tax returns are currently under audit.
Regulation - Our distribution
operations and ONEOK Partners’ intrastate natural gas transmission pipelines are
subject to the rate regulation and accounting requirements of the OCC, KCC, RRC
and various municipalities in Texas. ONEOK Partners’ interstate
natural gas and natural gas liquids pipelines are subject to regulation by the
FERC. In Kansas and Texas, natural gas storage may be regulated by
the state and the FERC for certain types of services. Oklahoma
Natural Gas, Kansas Gas Service, Texas Gas Service and portions of our ONEOK
Partners segment follow the accounting and reporting guidance contained in
Statement 71, “Accounting for the Effects of Certain Types of
Regulation.” During the rate-making process, regulatory authorities
set the framework for what we can charge customers for our services and
establish the manner that our costs are accounted for, including allowing us to
defer recognition of certain costs and permitting recovery of the amounts
through rates over time as opposed to expensing such costs as
incurred. Certain examples of types of regulatory guidance include
costs for fuel and losses, acquisition costs, contributions in aid of
construction, charges for depreciation, and gains or losses on disposition of
assets. This allows us to stabilize rates over time rather than
passing such costs on to the customer for immediate recovery. Actions
by regulatory authorities could have an affect on the amount recovered from rate
payers. Any difference in the amount recoverable and the amount
deferred is recorded as income or expense at the time of the regulatory
action. If all or a portion of the regulated operations are no longer
subject to the provisions of Statement 71, a write-off of regulatory assets and
costs not recovered may be required.
At
December 31, 2008 and 2007, we recorded regulatory assets of approximately
$523.3 million and $309.4 million, respectively, which are being recovered
through various rate cases or are expected to be
recovered. Regulatory assets are being recovered as a result of
approved rate proceedings over varying time periods up to 40
years. These assets are reflected in other assets on our Consolidated
Balance Sheets.
Asset Retirement Obligations -
Statement 143, “Accounting for Asset Retirement Obligations,” applies to legal
obligations associated with the retirement of long-lived assets that result from
the acquisition, construction, development and/or normal use of the
asset. Statement 143 requires that we recognize the fair value of a
liability for an asset retirement obligation in the period when it is incurred
if a reasonable estimate of the fair value can be made. The fair
value of the liability is added to the carrying amount of the associated asset,
and this additional carrying amount is depreciated over the life of the
asset. The liability is accreted at the end of each period through
charges to operating expense. If the obligation is settled for an
amount other than the carrying amount of the liability, we will recognize a gain
or loss on settlement. The depreciation and amortization expense is
immaterial to our consolidated financial statements.
In
accordance with long-standing regulatory treatment, we collect through rates the
estimated costs of removal on certain regulated properties through depreciation
expense, with a corresponding credit to accumulated depreciation and
amortization. These removal costs are non-legal obligations as
defined by Statement 143. However, these non-legal asset-removal
obligations are accounted for as a regulatory liability under Statement
71. Historically, the regulatory authorities that have jurisdiction
over our regulated operations have not required us to track this amount; rather,
these costs are addressed prospectively as depreciation rates and are set in
each general rate order. We have made an estimate of our removal cost
liability using current rates since the last general rate order in each of our
jurisdictions. However, significant uncertainty exists regarding the
ultimate determination of this liability, pending, among other issues,
clarification of regulatory intent. We continue to monitor the
regulatory authorities and the liability may be adjusted as more information is
obtained. We have reclassified the estimated non-legal asset removal
obligation from accumulated deprecation and amortization to non-current
liabilities in other deferred credits on our Consolidated Balance
Sheets. To the extent this estimated liability is adjusted, such
amounts will be reclassified between accumulated depreciation and amortization
and other deferred credits and therefore will not have an impact on
earnings.
Share-Based Payment -
Statement 123R, “Share-Based Payment,” requires companies to expense the fair
value of share-based payments net of estimated forfeitures. We
adopted Statement 123R as of January 1, 2006, and elected to use the modified
prospective method. Statement 123R did not have a material impact on
our consolidated financial statements as we have been expensing share-based
payments since our adoption of Statement 148, “Accounting for Stock-Based
Compensation - Transition and Disclosure,” on January 1, 2003. Awards
granted after the adoption of Statement 123R are expensed under the requirements
of Statement 123R, while equity awards granted prior to the adoption of
Statement 123R will continue to be expensed under Statement
148.
Earnings per Common Share -
Basic EPS is calculated based on the daily weighted-average number of shares of
common stock outstanding during the period. Diluted EPS is calculated
based on the daily weighted-average number of shares of common stock outstanding
during the period plus potentially dilutive components. The dilutive
components are calculated based on the dilutive effect for each
quarter. For fiscal year periods, the dilutive components for each
quarter are averaged to arrive at the fiscal year-to-date dilutive
component.
Other
Master Netting
Arrangements - In April
2007, the FASB issued FSP FIN 39-1, “Amendment of FASB Interpretation No. 39,”
which requires entities that offset the fair value amounts recognized for
derivative receivables and payables to also offset the fair value amounts
recognized for the right to reclaim cash collateral with the same counterparty
under a master netting arrangement. We applied the provisions of FSP
FIN 39-1 to our consolidated financial statements beginning January 1, 2008, and
the impact was not material. See Note C for applicable
disclosures.
Business Combinations - In
December 2007, the FASB issued Statement 141R, “Business Combinations,” which
will require most identifiable assets, liabilities, noncontrolling interest
(previously referred to as minority interest) and goodwill acquired in a
business combination to be recorded at fair value. Statement 141R was
effective for our year beginning January 1, 2009. Because the
provisions of Statement 141R are applied prospectively, our 2009 and subsequent
consolidated financial statements will not be impacted unless we complete a
business combination.
Noncontrolling Interests - In
December 2007, the FASB issued Statement 160, “Noncontrolling Interest in
Consolidated Financial Statements - an amendment to ARB No. 51,” which requires
a noncontrolling interest (previously referred to as minority interest) to be
reported as a component of equity. Statement 160 was effective for
our year beginning January 1, 2009, and requires retroactive adoption of the
presentation and disclosure requirements for existing minority interests
beginning with our March 31, 2009, Quarterly Report on Form
10-Q. Statement 160 is not expected to have a material impact on our
consolidated financial statements; however, certain financial statement
presentation changes and additional required disclosures will be
made.
Derivative Instruments and Hedging
Activities Disclosure - In March 2008, the FASB issued Statement 161,
“Disclosures about Derivative Instruments and Hedging Activities - an amendment
to FASB Statement No. 133,” which requires enhanced disclosures about how
derivative and hedging activities affect our financial position, financial
performance and cash flows. Statement 161 was effective for our year
beginning January 1, 2009, and will be applied prospectively beginning with our
March 31, 2009, Quarterly Report on Form 10-Q.
Equity Method Investments - In
November 2008, the FASB ratified EITF 08-6, “Equity Method Investment Accounting
Considerations,” which clarified certain issues that arose following the
issuance of Statements 141R and 160 related to the accounting for equity method
investments. EITF 08-6 was effective for our year beginning January
1, 2009, and is not expected to have a material impact on our consolidated
financial statements.
Postretirement Benefit Plan
Assets - In December 2008, the FASB issued FSP FAS 132R-1, “Employers’
Disclosures about Postretirement Benefit Plan Assets,” which amends Statement
132R, “Employers’ Disclosures about Pensions and Other Postretirement Benefits,”
to require enhanced disclosures about our plan assets, including our investment
policies, major categories of plan assets, significant concentrations of risk
within plan assets, and inputs and valuation techniques used to measure the fair
value of plan assets. FSP FAS 132R-1 is effective for our fiscal year
ending December 31, 2009, and will be applied prospectively.
Reclassifications - Certain
amounts in our consolidated financial statements have been reclassified to
conform to the 2008 presentation. These reclassifications did not
impact previously reported net income or shareholders’ equity.
B. ACQUISITIONS
AND DIVESTITURES
Acquisition of NGL Pipeline -
In October 2007, ONEOK Partners completed the acquisition of an interstate
natural gas liquids and refined petroleum products pipeline system and related
assets from a subsidiary of Kinder Morgan Energy Partners, L.P. (Kinder Morgan)
for approximately $300 million, before working capital
adjustments. The system extends from Bushton and Conway, Kansas, to
Chicago, Illinois, and transports, stores and delivers a full range of NGL and
refined petroleum products. The FERC-regulated system spans 1,624
miles and has a capacity to transport up to 134 MBbl/d. The
transaction also included approximately 978 MBbl of owned storage capacity,
eight NGL terminals and a 50 percent
ownership
of Heartland. ConocoPhillips owns the other 50 percent of Heartland
and is the managing partner of the Heartland joint venture, which consists
primarily of a refined petroleum products terminal and pipelines with access to
two other refined petroleum products terminals. ONEOK Partners’
investment in Heartland is accounted for under the equity method of
accounting. Financing for this transaction came from a portion of the
proceeds of ONEOK Partners’ September 2007 issuance of $600 million 6.85 percent
Senior Notes due 2037 (the 2037 Notes). See Note I for a discussion
of the 2037 Notes. The working capital settlement was finalized in
April 2008, with no material adjustments.
Overland Pass Pipeline Company
- In May 2006, a subsidiary of ONEOK Partners entered into an agreement with a
subsidiary of The Williams Companies, Inc. (Williams) to form a joint venture
called Overland Pass Pipeline Company. In November 2008, Overland
Pass Pipeline Company completed construction of a 760-mile natural gas liquids
pipeline from Opal, Wyoming, to the Mid-Continent natural gas liquids market
center in Conway, Kansas. The Overland Pass Pipeline is designed to
transport approximately 110 MBbl/d of unfractionated NGLs and can be increased
to approximately 255 MBbl/d with additional pump facilities. During
2006, ONEOK Partners paid $11.6 million to Williams for the acquisition of its
interest in the joint venture and for reimbursement of initial capital
expenditures. A subsidiary of ONEOK Partners owns 99 percent of the
joint venture, managed the construction project, advanced all costs associated
with construction and is currently operating the pipeline. On or
before November 17, 2010, Williams will have the option to increase its
ownership up to 50 percent, with the purchase price being determined in
accordance with the joint venture’s operating agreement. If Williams
exercises its option to increase its ownership to the full 50 percent, Williams
would have the option to become operator. The pipeline project cost
was approximately $575 million, excluding AFUDC.
As part
of a long-term agreement, Williams dedicated its NGL production from two of its
natural gas processing plants in Wyoming to the Overland Pass
Pipeline. Subsidiaries of ONEOK Partners will provide downstream
fractionation, storage and transportation services to Williams.
ONEOK Partners - In April 2006, we sold
certain assets comprising our former gathering and processing, natural gas
liquids, and pipelines and storage segments to ONEOK Partners for approximately
$3 billion, including $1.35 billion in cash, before adjustments, and
approximately 36.5 million Class B limited partner units in ONEOK
Partners. The Class B limited partner units and the related general
partner interest contribution were valued at approximately $1.65
billion. We also purchased, through ONEOK Partners GP, from an
affiliate of TransCanada, 17.5 percent of the general partner interest in ONEOK
Partners for $40 million. This purchase resulted in our ownership of
the entire 2 percent general partner interest in ONEOK
Partners. Following the completion of the transactions, we owned a
total of approximately 37.0 million common and Class B limited partner units and
the entire 2 percent general partner interest and control the
partnership. Our overall interest in ONEOK Partners, including the 2
percent general partner interest, was 45.7 percent at the date of
acquisition.
Disposition of 20 percent interest in
Northern Border Pipeline - In April 2006, in connection with the
transactions described immediately above, our ONEOK Partners segment completed
the sale of a 20 percent partnership interest in Northern Border Pipeline to TC
PipeLines for approximately $297 million. Our ONEOK Partners segment
recorded a gain on the sale of approximately $113.9 million in the second
quarter of 2006. ONEOK Partners and TC PipeLines each now own a 50
percent interest in Northern Border Pipeline, and an affiliate of TransCanada
became operator of the pipeline in April 2007. Neither ONEOK Partners
nor TC PipeLines has control of Northern Border Pipeline, as control is shared
equally through Northern Border Pipeline’s Management Committee. As a
result of this transaction, ONEOK Partners’ interest in Northern Border Pipeline
has been accounted for as an investment under the equity method, applied on a
retroactive basis to January 1, 2006.
Acquisition of Guardian Pipeline
Interests - In April 2006, our ONEOK Partners segment acquired the 66-2/3
percent interest in Guardian Pipeline not previously owned by ONEOK Partners for
approximately $77 million, increasing its ownership interest to 100
percent. ONEOK Partners used borrowings from its credit facility to
fund the acquisition of the additional interest in Guardian
Pipeline. Following the completion of the transaction, we
consolidated Guardian Pipeline in our consolidated financial
statements. This change was accounted for on a retroactive basis to
January 1, 2006.
C. FAIR
VALUE MEASUREMENTS
See Note
A for a discussion of our fair value measurements and the fair value
hierarchy.
Recurring Fair Value
Measurements - The following table sets forth our recurring fair value
measurements for the period indicated.
|
|
December
31, 2008
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Netting
(a)
|
|
|
Total
|
|
|
|
(Thousands
of dollars)
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
$ |
580,029 |
|
|
$ |
215,116 |
|
|
$ |
454,377 |
|
|
$ |
(840,814 |
) |
|
$ |
408,708 |
|
Trading
securities
|
|
|
4,910 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,910 |
|
Available-for-sale
investment securities
|
|
|
1,665 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,665 |
|
Fair
value of firm commitments
|
|
|
- |
|
|
|
- |
|
|
|
42,179 |
|
|
|
- |
|
|
|
42,179 |
|
Total
assets
|
|
$ |
586,604 |
|
|
$ |
215,116 |
|
|
$ |
496,556 |
|
|
$ |
(840,814 |
) |
|
$ |
457,462 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivatives
|
|
$ |
(501,726 |
) |
|
$ |
(55,705 |
) |
|
$ |
(412,022 |
) |
|
$ |
748,136 |
|
|
$ |
(221,317 |
) |
Long-term
debt swapped to floating
|
|
|
- |
|
|
|
- |
|
|
|
(171,455 |
) |
|
|
- |
|
|
|
(171,455 |
) |
Total
liabilities
|
|
$ |
(501,726 |
) |
|
$ |
(55,705 |
) |
|
$ |
(583,477 |
) |
|
$ |
748,136 |
|
|
$ |
(392,772 |
) |
(a)
- Our derivative assets and liabilities are presented in our Consolidated
Balance Sheets on a net basis. We net derivative assets and
liabilities, including cash collateral in accordance with FSP FIN 39-1,
when a legally enforceable master netting arrangement exists between us
and the counterparty to a derivative contract. At December 31, 2008,
we held $92.7 million of cash collateral.
|
|
For
derivatives for which fair value is determined based on multiple inputs,
Statement 157 requires that the measurement for an individual derivative be
categorized within a single level based on the lowest-level input that is
significant to the fair value measurement in its entirety.
Our Level
1 fair value measurements are based on NYMEX-settled prices, actively quoted
prices for equity securities and foreign currency forward exchange
rates. These balances are predominantly comprised of exchange-traded
derivative contracts, including futures and certain options for natural gas and
crude oil, that are valued based on unadjusted quoted prices in active
markets. Also included in Level 1 are available-for-sale and trading
securities and foreign currency forwards.
Our Level
2 fair value inputs are based on NYMEX-settled prices that are utilized to
determine the fair value of certain non-exchange-traded financial instruments,
including natural gas and crude oil swaps.
Our Level
3 inputs are based on over-the-counter quotes, market volatilities derived from
NYMEX-settled prices, internally developed basis curves incorporating observable
and unobservable market data, modeling techniques using observable market data
and historical correlations of NGL product prices to crude oil, and spot and
forward LIBOR curves. The derivatives categorized as Level 3 include
over-the-counter swaps and options for natural gas and crude oil, NGL swaps and
forwards, natural gas basis and swing swaps and physical forward contracts, and
interest-rate swaps. Also included in Level 3 are the fair values of
firm commitments and long-term debt that have been hedged.
Transfers
in and out of Level 3 typically result from derivatives for which fair value is
determined based on multiple inputs. Since we categorize our
derivatives based on the lowest level input that is significant, a derivative
can move between Level 2 and Level 3 as the value of the various inputs
changes.
The
following table sets forth the reconciliation of our Level 3 fair value
measurements for the period indicated.
|
|
Derivative
Assets
(Liabilities)
|
|
|
Fair
Value of
Firm
Commitments
|
|
|
Long-Term
Debt
|
|
|
Total
|
|
|
|
(Thousands
of dollars)
|
|
January
1, 2008
|
|
$ |
(54,582 |
) |
|
$ |
42,684 |
|
|
$ |
(338,538 |
) |
|
$ |
(350,436 |
) |
Total
realized/unrealized gains (losses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included
in earnings (a)
|
|
|
6,080 |
|
|
|
(505 |
) |
|
|
(2,917 |
) |
|
|
2,658 |
|
Included
in other comprehensive
income
(loss)
|
|
|
84,592 |
|
|
|
- |
|
|
|
- |
|
|
|
84,592 |
|
Terminations
prior to maturity
|
|
|
(5,074 |
) |
|
|
- |
|
|
|
170,000 |
|
|
|
164,926 |
|
Transfers
in and/or out of Level 3
|
|
|
11,339 |
|
|
|
- |
|
|
|
- |
|
|
|
11,339 |
|
December
31, 2008
|
|
$ |
42,355 |
|
|
$ |
42,179 |
|
|
$ |
(171,455 |
) |
|
$ |
(86,921 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
gains (losses) for the period included in
earnings
attributable to the change in unrealized
gains
(losses) relating to assets and liabilities
still
held as of December 31, 2008 (a)
|
|
$ |
(116,127 |
) |
|
$ |
153,221 |
|
|
$ |
(2,917 |
) |
|
$ |
34,177 |
|
(a)
- Reported in revenues in our Consolidated Statements of
Income.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized/unrealized
gains (losses) include the realization of our fair value derivative contracts
through maturity, changes in fair value of our hedged firm commitments and
fixed-rate debt swapped to floating. Terminations prior to maturity
represents swap contracts terminated prior to maturity that will
remain in accumulated other comprehensive income (loss) until the
underlying forecasted transaction occurs; and the long-term debt associated with
the interest rate swaps that were terminated during the
period. Transfers into Level 3 represent existing assets or
liabilities that were previously categorized at a higher level for which the
inputs to our models became unobservable. Transfers out of Level 3
represent existing assets and liabilities that were previously classified as
Level 3 for which the inputs became observable in accordance with our hierarchy
policy discussed on page 78.
Fair Value - The following
table represents the fair value of our energy marketing and risk management
assets and liabilities for the periods indicated.
|
|
December
31, 2008
|
|
|
December
31, 2007
|
|
|
|
Assets
|
|
|
Liabilities
|
|
|
Assets
|
|
|
Liabilities
|
|
|
|
(Thousands
of dollars)
|
|
Energy
Services - financial non-trading instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange-traded
instruments
|
|
$ |
31,509 |
|
|
$ |
640 |
|
|
$ |
4,739 |
|
|
$ |
14,853 |
|
Over-the-counter
swaps
|
|
|
73,095 |
|
|
|
1,624 |
|
|
|
41,633 |
|
|
|
19,160 |
|
Options
|
|
|
186 |
|
|
|
- |
|
|
|
1,887 |
|
|
|
2,467 |
|
Other
(a)
|
|
|
39,453 |
|
|
|
2,515 |
|
|
|
7,469 |
|
|
|
2,741 |
|
|
|
|
144,243 |
|
|
|
4,779 |
|
|
|
55,728 |
|
|
|
39,221 |
|
Energy
Services - financial trading instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exchange-traded
instruments
|
|
|
6,158 |
|
|
|
144 |
|
|
|
1,641 |
|
|
|
888 |
|
Over-the-counter
swaps
|
|
|
14,002 |
|
|
|
321 |
|
|
|
11,258 |
|
|
|
8,013 |
|
Options
|
|
|
7,043 |
|
|
|
191 |
|
|
|
14,173 |
|
|
|
18,654 |
|
Other
(a)
|
|
|
358 |
|
|
|
249 |
|
|
|
420 |
|
|
|
287 |
|
|
|
|
27,561 |
|
|
|
905 |
|
|
|
27,492 |
|
|
|
27,842 |
|
ONEOK
Partners - cash flow hedges
|
|
|
63,780 |
|
|
|
- |
|
|
|
- |
|
|
|
21,304 |
|
Distribution
- natural gas swaps
|
|
|
- |
|
|
|
23,003 |
|
|
|
- |
|
|
|
9,752 |
|
Energy
Services - cash flow hedges
|
|
|
62,250 |
|
|
|
44,248 |
|
|
|
57,966 |
|
|
|
8,344 |
|
Energy
Services - fair value hedges
|
|
|
109,419 |
|
|
|
148,382 |
|
|
|
5,237 |
|
|
|
51,343 |
|
Interest
rate swaps - fair value hedges
|
|
|
1,455 |
|
|
|
- |
|
|
|
1,496 |
|
|
|
2,958 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
fair value
|
|
$ |
408,708 |
|
|
$ |
221,317 |
|
|
$ |
147,919 |
|
|
$ |
160,764 |
|
(a)
- Other includes physical natural gas.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial Instruments - The following
information represents the carrying amounts and estimated fair values of our
financial instruments for the periods indicated, excluding energy marketing and
risk management assets and liabilities, which are listed in the table
above.
The
approximate fair value of cash and cash equivalents, short-term investments,
accounts and notes receivable and accounts and notes payable is equal to book
value, due to their short-term nature. The estimated fair value of
long-term debt has been determined using quoted market prices of the same or
similar issues, discounted cash flows, and/or rates currently available to us
for debt with similar terms and remaining maturities. The book value
of our long-term debt was $4.23 billion and $4.64 billion at December 31, 2008
and 2007, respectively. The approximate fair value of our long-term
debt was $3.95 billion and $4.75 billion at December 31, 2008 and 2007,
respectively.
The
tables below show information about our investment securities classified as
available-for-sale.
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
(Thousands
of dollars)
|
|
Available-for-sale
securities held
|
|
|
|
|
|
|
|
|
|
Aggregate
fair value
|
|
$ |
1,665 |
|
|
$ |
24,151 |
|
|
$ |
22,416 |
|
Reported
in accumulated other
comprehensive
income (loss) for net
unrealized
holding gains
|
|
$ |
815 |
|
|
$ |
13,678 |
|
|
$ |
12,614 |
|
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands
of dollars)
|
|
Available-for-sale
securities held
|
|
|
|
|
|
|
|
|
|
Gains
reclassified to earnings
from
accumulated other
comprehensive
income (loss)
|
|
$ |
11,142 |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Available-for-sale
securities sold
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from sale (a)
|
|
$ |
3,886 |
|
|
$ |
- |
|
|
$ |
- |
|
Gain
from sale (a)
|
|
$ |
3,369 |
|
|
$ |
- |
|
|
$ |
- |
|
(a)
- We sold a portion of our available-for-sale securities and used specific
identification
to
determine the cost of the securities sold.
|
|
We
transferred securities from available-for-sale to trading during the year ended
December 31, 2008, and recognized a $7.7 million gain, due to a reconsideration
event in August 2008 when our NYMEX Holding, Inc. Class A shares held were
converted to CME Group, Inc. (CME) Class A shares due to the NYMEX Holding, Inc.
and CME merger. A modification was made to the number of shares
required to be maintained by NYMEX Holding, Inc. Class A Members which resulted
in our sale of certain shares and the reclassification of the remaining shares
to trading. These trading securities were still held as of December
31, 2008.
The gains
reclassified into earnings from accumulated other comprehensive income (loss)
for the year ended December 31, 2008, of $11.1 million include the $7.7 million
gain discussed in the previous paragraph, as well as a $3.4 million realized
gain on the sale of available-for-sale securities.
D. ENERGY
MARKETING AND RISK MANAGEMENT ACTIVITIES
Risk Policy and Oversight -
Market risks are monitored by our risk control group that is responsible for
ensuring compliance with our risk management policies.
We
control the scope of risk management, marketing and trading operations through a
comprehensive set of policies and procedures involving senior levels of
management. The Audit Committee of our Board of Directors has
oversight responsibilities for our risk management limits and
policies. Our risk oversight committee, comprised of corporate and
business segment officers, oversees all activities related to commodity price
and credit risk management, and marketing and
trading
activities. The committee also monitors risk metrics including
value-at-risk (VAR) and mark-to-market losses. We have a corporate
risk control organization that is assigned responsibility for establishing and
enforcing the policies and procedures and monitoring certain risk
metrics. Key risk control activities include credit review and
approval, credit and performance risk measurement and monitoring, validation of
transactions, portfolio valuation, VAR and other risk metrics.
Commodity and Interest Rate Risk
Management Activities - Our operating results are affected by commodity
price fluctuations. We routinely enter into derivative financial
instruments to minimize the risk of commodity price fluctuations related to
anticipated sales of natural gas and condensate, NGLs, purchase and sale
commitments, fuel requirements, currency exposure, transportation and storage
contracts, and natural gas inventories. We are also subject to the
risk of interest-rate fluctuations in the normal course of
business. We manage interest-rate risk through the use of fixed-rate
debt, floating-rate debt and, at times, interest-rate swaps.
Our
Energy Services segment includes our wholesale and retail natural gas marketing
and financial trading operations. Our Energy Services segment
mitigates the commodity risk associated with our fixed-price physical purchase
and sale commitments through the use of derivative instruments. With
respect to the net open positions that exist within our marketing and financial
trading operations, fluctuating commodity market prices can impact our financial
position and results of operations, either favorably or
unfavorably. The net open positions are actively managed, and the
impact of the changing prices on our financial condition at a point in time is
not necessarily indicative of the impact of price movements throughout the
year.
Operating
margins associated with ONEOK Partners’ natural gas gathering and processing and
natural gas liquids gathering and fractionation businesses are sensitive to
changes in natural gas, condensate and NGL prices, principally as a result of
contractual terms under which natural gas is processed and products are
sold. ONEOK Partners uses physical forward sales and derivative
instruments to secure a certain price for natural gas, condensate and NGL
products.
Our
Distribution segment also uses derivative instruments to hedge the cost of
anticipated natural gas purchases during the winter heating months to protect
their customers from upward volatility in the market price of natural
gas. Gains or losses associated with these derivative instruments are
included in, and recoverable through, the monthly purchased gas cost
mechanism.
Accounting Treatment - We
account for derivative instruments and hedging activities in accordance with
Statement 133. Under Statement 133, entities are required to record derivative
instruments at fair value, with the exception of normal purchases and normal
sales that are expected to result in physical delivery. The
accounting for changes in the fair value of a derivative instrument depends on
whether it has been designated and qualifies as part of a hedging relationship
and, if so, the reason for holding it. If the derivative instrument
does not qualify or is not designated as part of a hedging relationship, we
account for changes in fair value of the derivative instrument in earnings as
they occur. We record changes in the fair value of derivative
instruments that are considered held for trading purposes as revenues and
derivative instruments considered not held for trading purposes as cost of sales
and fuel in our Consolidated Statements of Income. If certain
conditions are met, entities may elect to designate a derivative instrument as a
hedge of exposure to changes in fair values, cash flows or foreign
currencies. For hedges of exposure to changes in fair value, the gain
or loss on the derivative instrument is recognized in earnings during the period
of change together with the offsetting loss or gain on the hedged item
attributable to the risk being hedged. The difference between the
change in fair value of the derivative instrument and the change in fair value
of the hedged item represents hedge ineffectiveness, which is reported in
earnings during the period the ineffectiveness occurs. For hedges of
exposure to changes in cash flow, the effective portion of the gain or loss on
the derivative instrument is reported initially as a component of accumulated
other comprehensive income (loss) and is subsequently recorded in earnings when
the forecasted transaction affects earnings.
As
required by Statement 133, we formally document all relationships between
hedging instruments and hedged items, as well as risk management objectives,
strategies for undertaking various hedge transactions and methods for assessing
and testing correlation and hedge ineffectiveness. We specifically
identify the asset, liability, firm commitment or forecasted transaction that
has been designated as the hedged item. We assess the effectiveness
of hedging relationships by performing a regression analysis on our cash flow
and fair value hedging relationships quarterly to ensure the hedge relationships
are highly effective on a retrospective and prospective basis, as required by
Statement 133. We also document our normal physical purchases and
physical sales transactions that we elect to exempt from fair value accounting
treatment. Although we believe we have appropriate internal controls
over our accounting for derivatives, interpreting Statement 133 and the related
documentation requirements is very complex. In addition, future
interpretations may impact our application of Statement 133.
EITF
03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are
Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ as Defined
in EITF Issue No. 02-3,” provides that the determination of whether realized
gains and losses on physically settled derivative contracts not held for trading
purposes should be reported in the Consolidated Statements of Income on a gross
or net basis is a matter of judgment that depends on the relevant facts and
circumstances. Consideration of the facts and circumstances should be
made in the context of the various activities of the entity rather than based
solely on the terms of the individual contracts.
We
evaluate the accounting treatment related to the presentation of revenues from
the different types of activities to determine which amounts should be reported
on a gross or net basis under the guidance in EITF 03-11. For
derivative instruments considered held for trading purposes that result in
physical delivery, the indicators in EITF 02-3, “Issues Involved in Accounting
for Derivative Contracts Held for Trading Purposes and Contracts Involved in
Energy Trading and Risk Management Activities” are used to determine the proper
treatment. These activities and all financially settled derivative
contracts are reported on a net basis.
For
derivative instruments that are not considered held for trading purposes and
that result in physical delivery, the indicators in EITF 03-11 and EITF Issue
No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent,” are
used to determine the proper treatment. We account for the realized
revenues and purchase costs of these contracts that result in physical delivery
on a gross basis. We apply the indicators in EITF 99-19 to determine
the appropriate accounting treatment for non-derivative contracts that result in
physical delivery. Derivatives that qualify for the normal purchase
or sale exception as defined in Statement 133 are also reported on a gross
basis.
Cash
flows from futures, forwards, options and swaps that are accounted for as hedges
are included in the same cash flow statement category as the cash flows from the
related hedged items.
Fair Value Hedges - In 2008
and prior years, we and ONEOK Partners terminated various interest-rate swap
agreements. The net savings from the termination of these swaps is
being recognized in interest expense over the terms of the debt instruments
originally hedged. Net interest expense savings for 2008 from
amortization of terminated swaps was $10.5 million, and the remaining net
savings for all terminated swaps will be recognized over the following
periods.
|
|
|
|
|
ONEOK
|
|
|
|
|
|
|
ONEOK
|
|
|
Partners
|
|
|
Total
|
|
|
|
(Millions
of dollars)
|
|
2009
|
|
$ |
6.5 |
|
|
$ |
3.7 |
|
|
$ |
10.2 |
|
2010
|
|
$ |
6.4 |
|
|
$ |
3.7 |
|
|
$ |
10.1 |
|
2011
|
|
$ |
3.4 |
|
|
$ |
0.9 |
|
|
$ |
4.3 |
|
2012
|
|
$ |
1.7 |
|
|
$ |
- |
|
|
$ |
1.7 |
|
2013
|
|
$ |
1.7 |
|
|
$ |
- |
|
|
$ |
1.7 |
|
Thereafter
|
|
$ |
25.3 |
|
|
$ |
- |
|
|
$ |
25.3 |
|
At
December 31, 2008, the interest on $170 million of our fixed-rate debt was
swapped to floating using interest-rate swaps. The floating rate was
based on both the three- and six-month LIBOR, depending upon the
swap. Based on the actual performance for the year ended December 31,
2008, the weighted-average interest rate on the swapped debt decreased from 6.17
percent to 4.39 percent. At December 31, 2008, we recorded a net
asset of $1.5 million to recognize the interest-rate swaps at fair
value. Long-term debt includes an additional $1.5 million to
recognize the change in the fair value of the related hedged
debt. ONEOK Partners had no interest-rate swap agreements at December
31, 2008. See Note I for additional discussion of long-term
debt.
Our
Energy Services segment uses basis swaps to hedge the fair value of certain firm
transportation commitments. Net gains or losses from the fair value
hedges and ineffectiveness are recorded to cost of sales and
fuel. The ineffectiveness related to these hedges included losses of
$3.3 million, $5.3 million and $9.0 million for 2008, 2007 and 2006,
respectively.
In
September 2007, our Energy Services segment was notified that a portion of the
volume contracted under our firm transportation agreement with Cheyenne Plains
Gas Pipeline Company would be curtailed due to a fire at a Cheyenne Plains
pipeline compressor station. The fire damaged a significant amount of
instrumentation and electrical wiring, causing Cheyenne Plains Gas Pipeline
Company to declare a force majeure event on the pipeline. This firm
commitment was hedged in accordance with Statement 133. The
discontinuance of fair value hedge accounting on the portion of the firm
commitment
that was
impacted by the force majeure event resulted in a loss of approximately $5.5
million in the third quarter of 2007, of which $2.4 million of insurance
proceeds were recovered and recognized in the first quarter of
2008.
Cash Flow Hedges - Our Energy Services
segment uses derivative instruments to hedge the cash flows associated with our
anticipated purchases and sales of natural gas and the cost of fuel used in
transportation of natural gas. Accumulated other comprehensive income
(loss) at December 31, 2008, includes gains of approximately $10.3 million, net
of tax, related to these hedges that will be realized within the next 24 months
as forecasted transactions affect earnings. If prices remain at
current levels, we will recognize $7.2 million in net gains over the next 12
months, and we will recognize net gains of $3.1 million
thereafter. In accordance with Statement 133, the actual gains or
losses will be reclassified into earnings when the related physical transactions
affect earnings.
During
the third and fourth quarters of 2008, the carrying value of natural gas in
storage was written down by $308.5 million in order to record inventory at the
lower of cost or market. As required by Statement 133, we
reclassified $298.8 million of deferred gains, before income taxes, on
associated cash flow hedges from accumulated other comprehensive income (loss)
into earnings.
Through
an affiliate, our ONEOK Partners segment periodically enters into derivative
instruments to hedge the cash flows associated with its exposure to changes in
the price of natural gas, NGLs and condensate. At December 31, 2008,
our ONEOK Partners’ segment reflected an unrealized gain of $20.1 million, net
of tax, in accumulated other comprehensive income (loss), with a corresponding
offset in energy marketing and risk management assets and liabilities, all of
which will be recognized over the next 12 months.
Ineffectiveness
related to our cash flow hedges resulted in gains of approximately $1.4 million,
$0.2 million and $15.0 million in 2008, 2007 and 2006,
respectively. In the event that it becomes probable that a forecasted
transaction will not occur, we would discontinue cash flow hedge treatment,
which would affect earnings. There were no material gains or losses
in 2008, 2007 or 2006 due to the discontinuance of cash flow hedge
treatment.
Credit Risk - We maintain
credit policies with regard to our counterparties that we believe minimize
overall credit risk. These policies include an evaluation of
potential counterparties’ financial condition (including credit ratings and
credit default swap rates), collateral requirements under certain circumstances
and the use of standardized agreements which allow for netting of positive and
negative exposures associated with a single counterparty.
Our
counterparties consist primarily of financial institutions, major energy
companies, LDCs, electric utilities and commercial and industrial
end-users. This concentration of counterparties may impact our
overall exposure to credit risk, either positively or negatively, in that the
counterparties may be similarly affected by changes in economic, regulatory or
other conditions. Based on our policies, exposures, credit and other
reserves, we do not anticipate a material adverse effect on our financial
position or results of operations as a result of counterparty
nonperformance.
E. GOODWILL
AND INTANGIBLE ASSETS
Goodwill
Carrying Amount - The
following table sets forth goodwill recorded on our Consolidated Balance Sheets
for the periods indicated.
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands
of dollars)
|
|
ONEOK
Partners
|
|
$ |
433,537 |
|
|
$ |
431,418 |
|
Distribution
|
|
|
157,953 |
|
|
|
157,953 |
|
Energy
Services
|
|
|
10,255 |
|
|
|
10,255 |
|
Other
|
|
|
1,099 |
|
|
|
1,099 |
|
Total
Goodwill
|
|
$ |
602,844 |
|
|
$ |
600,725 |
|
Equity Method Goodwill - For
the investments we account for under the equity method, the premium or excess
cost over underlying fair value of net assets is referred to as equity method
goodwill. Investment in unconsolidated affiliates on our accompanying
Consolidated Balance Sheets includes equity method goodwill of $185.6 million as
of December 31, 2008 and 2007.
Impairment Test - We apply the
provisions of Statement 142 and perform our annual impairment test on July
1. There were no impairment charges resulting from our July 1, 2008,
impairment test. As a result of recent events in the financial
markets and current economic conditions, we performed a review and determined
that interim testing of goodwill as of December 31, 2008, was not
necessary.
Black Mesa - During 2006, we
recorded a goodwill and asset impairment related to ONEOK Partners’ Black Mesa
Pipeline of $8.4 million and $3.6 million, respectively, which was recorded as
depreciation and amortization. The reduction to our net income, net
of minority interests and income taxes, was $3.0 million.
Intangible
Assets
Our ONEOK
Partners segment had $279.8 million of intangible assets primarily related to
acquired contracts, which are being amortized over an aggregate weighted-average
period of 40 years. The remaining intangible asset balance has an
indefinite life. Amortization expense for intangible assets for both
2008 and 2007 was $7.7 million, and the aggregate amortization expense for each
of the next five years is estimated to be approximately $7.7
million. The following table reflects the gross carrying amount and
accumulated amortization of intangible assets for the periods
presented.
|
|
Gross
|
|
|
Accumulated
|
|
|
Net
|
|
|
|
Intangible
Assets
|
|
|
Amortization
|
|
|
Intangible
Assets
|
|
|
(Thousands
of dollars)
|
December
31, 2007
|
|
$ |
462,214 |
|
|
$ |
(19,166 |
) |
|
$ |
443,048 |
|
December
31, 2008
|
|
$ |
462,214 |
|
|
$ |
(26,832 |
) |
|
$ |
435,382 |
|
F. OTHER
COMPREHENSIVE INCOME (LOSS)
The table
below shows the gross amount of other comprehensive income (loss) and related
tax (expense) benefit for the periods indicated.
|
|
|
|
Year
Ended
|
|
|
|
|
|
Year
Ended
|
|
|
|
|
|
December
31, 2008
|
|
December
31, 2007
|
|
|
|
Gross
|
|
Tax
(Expense) or Benefit
|
|
Net
|
|
Gross
|
|
Tax
(Expense)
or
Benefit
|
|
Net
|
|
|
|
(Thousands
of dollars)
|
|
Unrealized
gains on energy
marketing
and risk
management
assets/liabilities
|
|
$ |
276,400 |
|
|
(103,705 |
) |
$ |
172,695 |
|
$ |
48,888 |
|
$ |
(21,836 |
) |
$ |
27,052 |
|
Less: Gains
on energy marketing and
risk
management assets/liabilities
recognized
in net income
|
|
|
277,413 |
|
|
(107,303 |
) |
|
170,110 |
|
|
149,535 |
|
|
(57,840 |
) |
|
91,695 |
|
Unrealized
holding gains (losses) on
investment
securities arising
during
the period
|
|
|
(9,837 |
) |
|
3,805 |
|
|
(6,032 |
) |
|
1,735 |
|
|
(671 |
) |
|
1,064 |
|
Less: Gains
on investment securities
recognized
in net income
|
|
|
11,142 |
|
|
(4,310 |
) |
|
6,832 |
|
|
- |
|
|
- |
|
|
- |
|
Change
in pension and postretirement
benefit
plan liability
|
|
|
(86,869 |
) |
|
33,601 |
|
|
(53,268 |
) |
|
27,687 |
|
|
(10,709 |
) |
|
16,978 |
|
Other
comprehensive income (loss)
|
|
$ |
(108,861 |
) |
$ |
45,314 |
|
$ |
(63,547 |
) |
$ |
(71,225 |
) |
$ |
24,624 |
|
$ |
(46,601 |
) |
The gains
on energy marketing and risk management assets/liabilities recognized in net
income presented in the table above include the reclassification of gains on our
cash flow hedges from accumulated other comprehensive income (loss) into
earnings as discussed in Note D.
The table
below shows the balance in accumulated other comprehensive income (loss) for the
periods indicated.
|
|
Unrealized
Gains (Losses) on Energy Marketing and Risk Management
Assets/Liabilities
|
|
Unrealized
Holding
Gains
(Losses) on
Investment
Securities
|
|
Pension
and Postretirement Benefit Plan Obligations
|
|
Accumulated
Other Comprehensive Income (Loss)
|
|
|
|
(Thousands
of dollars)
|
|
December
31, 2006
|
|
$ |
89,971
|
|
|
$ |
12,614
|
|
|
$ |
(63,053)
|
|
|
$ |
39,532
|
|
Other
comprehensive income (loss)
|
|
|
(64,643)
|
|
|
|
1,064
|
|
|
|
16,978
|
|
|
|
(46,601)
|
|
December
31, 2007
|
|
$ |
25,328
|
|
|
$ |
13,678
|
|
|
$ |
(46,075)
|
|
|
$ |
(7,069)
|
|
Other
comprehensive income (loss)
|
|
|
2,585
|
|
|
|
(12,864)
|
|
|
|
(53,268)
|
|
|
|
(63,547)
|
|
December
31, 2008
|
|
$ |
27,913
|
|
|
$ |
814
|
|
|
$ |
(99,343)
|
|
|
$ |
(70,616)
|
|
G. CAPITAL
STOCK
Series A and B Convertible Preferred
Stock - There are no shares of Series A or Series B currently
outstanding.
Series C Preferred Stock
- Series C
Preferred Stock (Series C) is designed to protect our shareholders from coercive
or unfair takeover tactics. If issued, holders of shares of Series C
are entitled to receive, in preference to the holders of ONEOK Common Stock,
quarterly dividends in an amount per share equal to the greater of $0.50 or,
subject to adjustment, 100 times the aggregate per share amount of all cash
dividends, and 100 times the aggregate per share amount (payable in kind) of all
non-cash dividends. No shares of Series C have been
issued.
Common Stock - At December 31,
2008, we had approximately 175 million shares of authorized and unreserved
common stock available for issuance.
Stock Repurchase Plan - On May
17, 2007, our Board of Directors authorized a stock buy back program to
repurchase up to 7.5 million shares of our currently issued and outstanding
common stock. On June 28, 2007, we repurchased 7.5 million shares of
our outstanding common stock under an accelerated share repurchase agreement
with Bank of America, N.A. (Bank of America) at an initial price of $49.33 per
share for a total of $370 million. Bank of America borrowed 7.5
million of our shares from third parties and purchased shares in the open market
to settle its short position. Our repurchase was subject to a
financial adjustment based on the volume-weighted average price, less a
discount, of the shares subsequently repurchased by Bank of America over the
course of the repurchase period. The price adjustment could have been
settled, at our option, in cash or in shares of our common stock. In
September 2007, the accelerated share repurchase agreement with Bank of America
was settled, which resulted in Bank of America delivering an additional 186,402
shares of our common stock to us at no additional cost. All shares
under this accelerated repurchase agreement were recorded as treasury shares in
our Consolidated Balance Sheets. These transactions completed the
plan approved by our Board of Directors and we have no remaining shares
available for repurchase under our stock repurchase plan.
On August
7, 2006, under a previously authorized stock repurchase plan, we repurchased 7.5
million shares of our outstanding common stock under an accelerated share
repurchase agreement with UBS Securities LLC (UBS) at an initial price of $37.52
per share for a total of $281.4 million. These shares were recorded
as treasury shares in our Consolidated Balance Sheets. UBS borrowed
7.5 million of our shares from third parties and purchased shares in the open
market to settle its short position. Our repurchase was subject to a
financial adjustment based on the volume-weighted average price, less a
discount, of the shares subsequently repurchased by UBS over the course of the
repurchase period. The price adjustment could have been settled, at
our option, in cash or in shares of our common stock. In February
2007, the forward purchase contract with UBS was settled for a cash payment of
$20.1 million, which was recorded in equity.
In
accordance with EITF Issue No. 99-7, “Accounting for an Accelerated Share
Repurchase Program,” the repurchases were accounted for as two separate
transactions: (i) as shares of common stock acquired in a treasury stock
transaction recorded on the acquisition date; and (ii) as a forward contract
indexed to our common stock. Additionally, we classified the forward
contracts as equity under EITF Issue No. 00-19, “Accounting for Derivative
Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own
Stock.”
Dividends - Quarterly
dividends paid on our common stock for shareholders of record as of the close of
business on January 31, 2008, April 30, 2008, July 31, 2008, and October 31,
2008, were $0.38 per share, $0.38 per share, $0.40 per share and $0.40 per
share, respectively. Additionally, a quarterly dividend of $0.40 per
share was declared in January 2009, payable in the first quarter of
2009.
Equity Units - On February 16,
2006, we successfully settled our 16.1 million equity units to 19.5 million
shares of our common stock. Of this amount, 8.3 million shares were
issued from treasury stock and approximately 11.2 million shares were newly
issued. Holders of the equity units received 1.2119 shares of our
common stock for each equity unit they owned. The number of shares
that we issued for each stock purchase contract was determined based on our
average closing price over the 20 trading day period ending on the third trading
day prior to February 16, 2006. With the settlement, we received
$402.4 million in cash, which was used to pay down our short-term bridge
financing agreement.
H. CREDIT
FACILITIES AND SHORT-TERM NOTES PAYABLE
ONEOK Credit Agreement - In July 2006 and September
2008, ONEOK amended and restated its $1.2 billion credit agreement (ONEOK Credit
Agreement). The amended agreement includes revised pricing, an
extension of the maturity date from 2009 to 2011, an option for additional
extensions of the maturity date with the consent of the lenders, an option to
request an increase in the commitments of the lenders of up to an additional
$500 million and a change in certain sublimits. The interest rates
applicable to extensions of credit under this agreement are based, at ONEOK’s
election, on either (i) the higher of prime or one-half of one percent above the
Federal Funds Rate, which is the rate that banks charge each other for the
overnight borrowing of funds; or (ii) the Eurodollar rate plus a set number of
basis points based on ONEOK’s current long-term unsecured debt
ratings.
Under the
ONEOK Credit Agreement, ONEOK is required to comply with certain financial,
operational and legal covenants. Among other things, these
requirements include:
·
|
a
$400 million sublimit for the issuance of standby letters of
credit;
|
·
|
a
limitation on ONEOK’s stand-alone debt-to-capital ratio, which may not
exceed 67.5 percent at the end of any calendar
quarter;
|
·
|
a
requirement that ONEOK maintains the power to control the management and
policies of ONEOK Partners; and
|
·
|
a
limit on new investments in master limited
partnerships.
|
The ONEOK
Credit Agreement also contains customary affirmative and negative covenants,
including covenants relating to liens, investments, fundamental changes in our
businesses, changes in the nature of ONEOK’s businesses, transactions with
affiliates, the use of proceeds and a covenant that prevents ONEOK from
restricting its subsidiaries’ ability to pay dividends.
ONEOK 364-Day Facility - In
August 2008, ONEOK entered into a $400 million 364-day credit agreement (364-Day
Facility). The interest rate is based, at ONEOK’s election, on either
(i) the higher of prime or one-half of one percent above the Federal Funds Rate;
or (ii) the Eurodollar rate plus a set number of basis points based on ONEOK’s
current long-term unsecured debt ratings by Moody’s and S&P. The
364-Day Facility is being used as an additional back-up to ONEOK’s commercial
paper program and for working capital, capital expenditures and other general
corporate purposes. The 364-Day Facility contains substantially
similar affirmative and negative covenants as the ONEOK Credit
Agreement.
The debt
covenant calculations in the ONEOK Credit Agreement and the 364-Day Facility
exclude the debt of ONEOK Partners. Upon breach of any covenant by
ONEOK, amounts outstanding under the ONEOK Credit Agreement or the 364-Day
Facility may become immediately due and payable. At December 31,
2008, ONEOK’s stand-alone debt-to-capital ratio was 58.2 percent and ONEOK was
in compliance with all covenants under the ONEOK Credit Agreement and the ONEOK
364-Day Facility.
At
December 31, 2008, ONEOK had no commercial paper outstanding, $1.4 billion in
borrowings outstanding and $64.6 million in letters of credit issued under the
ONEOK Credit Agreement, leaving $135.4 million of credit available under the
ONEOK Credit Agreement and 364-Day Facility. The ONEOK Credit
Agreement and the 364-Day Facility also serve as a back-up to ONEOK’s commercial
paper program.
The
average interest rate on ONEOK’s short-term debt outstanding was 4.51 percent
and 5.00 percent at December 31, 2008 and 2007, respectively.
At
December 31, 2007, ONEOK had $102.6 million in commercial paper outstanding, no
borrowings outstanding and $38.1 million in letters of credit issued under the
ONEOK Credit Agreement, leaving $1.1 billion of credit available under the ONEOK
Credit Agreement. In addition, ONEOK had $20.6 million in other
letters of credit issued at December 31, 2007.
ONEOK Partners Credit
Agreement - In March 2007, ONEOK Partners amended and restated its
revolving credit facility agreement (ONEOK Partners Credit Agreement), with
several banks and other financial institutions and lenders in the following
principal ways: (i) revised the pricing; (ii) extended the maturity by one year
to March 2012; (iii) eliminated the interest coverage ratio covenant; (iv)
increased the permitted ratio of indebtedness to EBITDA to 5 to 1 (from 4.75 to
1); (v) increased the swingline sub-facility commitments from $15 million to $50
million; and (vi) changed the permitted amount of subsidiary indebtedness from
$35 million to 10 percent of ONEOK Partners’ consolidated
indebtedness. The interest rates applicable to extensions of credit
under this agreement are based, at ONEOK Partners’ election, on either (i) the
higher of prime or one-half of one percent above the Federal Funds Rate, which
is the rate that banks charge each other for the overnight borrowing of funds;
or (ii) the Eurodollar rate plus a set number of basis points, depending on
ONEOK Partners’ current long-term unsecured debt ratings.
In July
2007, ONEOK Partners exercised the accordion feature in the ONEOK Partners
Credit Agreement to increase the commitment amounts by $250 million to a total
of $1.0 billion.
Under the
ONEOK Partners Credit Agreement, ONEOK Partners is required to comply with
certain financial, operational and legal covenants. Among other
things, these requirements include maintaining a ratio of indebtedness to
adjusted EBITDA (EBITDA plus minority interest in income of consolidated
subsidiaries, distributions received from investments and EBITDA related to any
approved capital projects less equity earnings from investments and the equity
portion of AFUDC) of no more than 5 to 1. If ONEOK Partners
consummates one or more acquisitions in which the aggregate purchase price is
$25 million or more, the allowable ratio of indebtedness to adjusted EBITDA will
be increased to 5.5 to 1 for the three calendar quarters following the
acquisition. Upon breach of any covenant, discussed above, amounts
outstanding under the ONEOK Partners Credit Agreement may become immediately due
and payable. At December 31, 2008, ONEOK Partners’ ratio of
indebtedness to adjusted EBITDA was 4.1 to 1, and ONEOK Partners was in
compliance with all covenants under the ONEOK Partners Credit
Agreement.
The
average interest rate of borrowings under the ONEOK Partners Credit Agreement
was 4.22 percent and 5.40 percent at December 31, 2008 and 2007,
respectively. ONEOK Partners had $870 million and $100 million of
borrowings outstanding and $130 million and $900 million available under the
ONEOK Partners Credit Agreement at December 31, 2008 and 2007,
respectively.
ONEOK
Partners has an outstanding $25 million letter of credit issued by Royal Bank of
Canada, which is used for counterparty credit support.
ONEOK
Partners also has a $15 million Senior Unsecured Letter of Credit Facility and
Reimbursement Agreement with Wells Fargo Bank, N.A., of which $12 million is
being used, and an agreement with Royal Bank of Canada, pursuant to which a $12
million letter of credit was issued. Both agreements are used to
support various permits required by the KDHE for ONEOK Partners’ ongoing
business in Kansas.
I. LONG-TERM
DEBT
The
following table sets forth our long-term debt for the periods
indicated. All notes are senior unsecured obligations, ranking
equally in right of payment with all of our existing and future unsecured senior
indebtedness.
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands
of dollars)
|
|
ONEOK
|
|
|
|
|
|
|
$402,500 at 5.51% due 2008
|
|
$ |
- |
|
|
$ |
402,303 |
|
$100,000
at 6.0% due 2009
|
|
|
100,000 |
|
|
|
100,000 |
|
$400,000
at 7.125% due 2011
|
|
|
400,000 |
|
|
|
400,000 |
|
$400,000
at 5.2% due 2015
|
|
|
400,000 |
|
|
|
400,000 |
|
$100,000
at 6.4% due 2019
|
|
|
91,371 |
|
|
|
92,000 |
|
$100,000
at 6.5% due 2028
|
|
|
89,970 |
|
|
|
90,902 |
|
$100,000
at 6.875% due 2028
|
|
|
100,000 |
|
|
|
100,000 |
|
$400,000
at 6.0% due 2035
|
|
|
400,000 |
|
|
|
400,000 |
|
Other
|
|
|
2,712 |
|
|
|
2,958 |
|
|
|
|
1,584,053 |
|
|
|
1,988,163 |
|
ONEOK
Partners
|
|
|
|
|
|
|
|
|
$250,000
at 8.875% due 2010
|
|
|
250,000 |
|
|
|
250,000 |
|
$225,000
at 7.10% due 2011
|
|
|
225,000 |
|
|
|
225,000 |
|
$350,000
at 5.90% due 2012
|
|
|
350,000 |
|
|
|
350,000 |
|
$450,000
at 6.15% due 2016
|
|
|
450,000 |
|
|
|
450,000 |
|
$600,000
at 6.65% due 2036
|
|
|
600,000 |
|
|
|
600,000 |
|
$600,000
at 6.85% due 2037
|
|
|
600,000 |
|
|
|
600,000 |
|
|
|
|
2,475,000 |
|
|
|
2,475,000 |
|
|
|
|
|
|
|
|
|
|
Guardian
Pipeline
|
|
|
|
|
|
|
|
|
Average
7.85%, due 2022
|
|
|
121,711 |
|
|
|
133,641 |
|
|
|
|
|
|
|
|
|
|
Total
long-term notes payable
|
|
|
4,180,764 |
|
|
|
4,596,804 |
|
Unamortized
portion of terminated
swaps
and fair value of hedged debt
|
|
|
55,035 |
|
|
|
43,682 |
|
Unamortized
debt premium
|
|
|
(5,023 |
) |
|
|
(4,961 |
) |
Current
maturities
|
|
|
(118,195 |
) |
|
|
(420,479 |
) |
Long-term
debt
|
|
$ |
4,112,581 |
|
|
$ |
4,215,046 |
|
The
aggregate maturities of long-term debt outstanding for the years 2009 through
2013 are shown below.
|
|
|
|
|
ONEOK
|
Guardian
|
|
|
|
|
ONEOK
|
|
Partners
|
Pipeline
|
|
Total
|
|
|
(Millions
of dollars)
|
2009
|
|
$ |
106.3
|
|
$
-
|
|
$ |
11.9
|
|
$ 118.2
|
2010
|
|
$ |
6.3
|
|
$
250.0
|
|
$ |
11.9
|
|
$ 268.2
|
2011
|
|
$ |
406.3
|
|
$
225.0
|
|
$ |
11.9
|
|
$ 643.2
|
2012
|
|
$ |
6.3
|
|
$
350.0
|
|
$ |
11.1
|
|
$ 367.4
|
2013
|
|
$ |
6.2
|
|
$
-
|
|
$ |
7.7
|
|
$ 13.9
|
|
|
|
|
|
|
|
|
|
|
|
Additionally,
$181.4 million of our debt is callable at par at our option from now until
maturity, which is 2019 for $91.4 million and 2028 for $90.0
million. Certain debt agreements have negative covenants that relate
to liens and sale/leaseback transactions.
ONEOK Partners’ Debt Issuance
- In
September 2007, ONEOK Partners completed an underwritten public offering of $600
million aggregate principal amount of 6.85 percent Senior Notes due 2037 (the
2037 Notes). The 2037 Notes were issued under ONEOK Partners’
existing shelf registration statement filed with the SEC.
ONEOK
Partners may redeem the 2037 Notes, in whole or in part, at any time prior to
their maturity at a redemption price equal to the principal amount of the 2037
Notes, plus accrued and unpaid interest and a make-whole premium. The
redemption price will never be less than 100 percent of the principal amount of
the 2037 Notes plus accrued and unpaid interest. The 2037 Notes are
senior unsecured obligations, ranking equally in right of payment with all of
ONEOK Partners’ existing and future unsecured senior indebtedness, and
effectively junior to all of the existing debt and other liabilities of its
non-guarantor subsidiaries. The 2037 Notes are non-recourse to
ONEOK.
Debt Covenants - The terms of
ONEOK’s long-term notes are governed by indentures containing covenants that
include, among other provisions, limitations on ONEOK’s ability to place liens
on its property or assets and its ability to sell and lease back its
property.
We filed
a new form of indenture in 2008. The new indenture includes covenants
that are similar to those contained in our prior indentures. The new
indenture does not limit the aggregate principal amount of debt securities that
may be issued and provides that debt securities may be issued from time to time
in one or more additional series.
The
indenture governing the 2037 Notes does not limit the aggregate principal amount
of debt securities that may be issued and provides that debt securities may be
issued from time to time in one or more additional series. The
indenture contains covenants including, among other provisions, limitations on
ONEOK Partners’ ability to place liens on its property or assets and its ability
to sell and lease back its property.
ONEOK
Partners’ $250 million and $225 million senior notes, due 2010 and 2011,
respectively, contain provisions that require ONEOK Partners to offer to
repurchase the senior notes at par value if its Moody’s or S&P credit rating
falls below investment grade (Baa3 for Moody’s or BBB- for S&P) and the
investment grade rating is not reinstated within a period of 40
days. Further, the indentures governing ONEOK Partners’ senior notes
due 2010 and 2011 include an event of default upon acceleration of other
indebtedness of $25 million or more and the indentures governing the senior
notes due 2012, 2016, 2036 and 2037 include 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, 2036 and 2037
to declare those notes immediately due and payable in full.
Guardian Pipeline Senior Notes
- These notes were issued under a master shelf agreement with certain financial
institutions. Principal payments are due quarterly through
2022. Interest rates on the $121.7 million in notes outstanding at
December 31, 2008, range from 7.61 percent to 8.27 percent, with an average rate
of 7.85 percent. Guardian Pipeline’s senior notes contain financial
covenants that require the maintenance of a ratio of (i) EBITDAR (net income
plus interest expense, income taxes, operating lease expense and depreciation
and amortization) to fixed charges (interest expense plus operating lease
expense) of not less than 1.5 to 1; and (ii) total indebtedness to EBITDAR of
not greater than 5.75 to 1. Upon any breach of these covenants, all
amounts outstanding under the master shelf agreement may become due and payable
immediately. At December 31, 2008, Guardian Pipeline’s
EBITDAR-to-fixed-charges ratio was 4.95 to 1, the ratio of total indebtedness to
EBITDAR was 3.34 to 1, and Guardian Pipeline was in compliance with its
financial covenants.
Other
We
amortize premiums, discounts and expenses incurred in connection with the
issuance of long-term debt consistent with the terms of the respective debt
instrument.
J. EMPLOYEE
BENEFIT PLANS
Retirement
and Other Postretirement Benefit Plans
Retirement Plans - We have
defined benefit retirement plans covering certain full-time
employees. Nonbargaining unit employees hired after December 31,
2004, are not eligible for our defined benefit pension plan; however, they are
covered by a defined contribution profit-sharing plan. Certain
officers and key employees are also eligible to participate in supplemental
retirement
plans. We generally fund pension costs at a level equal to the
minimum amount required under the Employee Retirement Income Security Act of
1974.
Other Postretirement Benefit
Plans - We sponsor welfare plans that provide postretirement medical and
life insurance benefits to certain employees who retire with at least five years
of service. The postretirement medical plan is contributory based on
hire date, age and years of service, with retiree contributions adjusted
periodically, and contains other cost-sharing features such as deductibles and
coinsurance.
Statement 158 - See Note A for
a discussion of the impact of the adoption of Statement 158, including the
change in our measurement date from September 30 to December 31.
Regulatory Treatment - The
OCC, KCC, and regulatory authorities in Texas have approved the recovery of
pension costs and other postretirement benefits costs through rates for Oklahoma
Natural Gas, Kansas Gas Service and Texas Gas Service,
respectively. The costs recovered through rates are based on current
funding requirements and the net periodic benefit cost for pension and
postretirement costs. Differences, if any, between the expense and
the amount recovered through rates are reflected in earnings.
Our
regulated entities have historically recovered pension and other postretirement
benefit costs, as determined by Statement 87, “Employers’ Accounting for
Pensions,” and Statement 106, “Employers’ Accounting for Postretirement Benefits
Other Than Pensions,” respectively, through rates. We believe it is
probable that regulators will continue to include the net periodic pension and
other postretirement benefit costs in our regulated entities’ cost of
service. Accordingly, we have recorded a regulatory asset for the minimum
liability associated with our regulated entities’ pension and other
postretirement benefit obligations that otherwise would have been recorded in
accumulated other comprehensive income.
Obligations and Funded Status
- The following tables set forth our pension and other postretirement benefit
plans benefit obligations and fair value of plan assets for the periods
indicated. Due to the change in our measurement date as discussed in
Note A, the changes in benefit obligation and plan assets shown in the following
tables are for the 15-month period from October 1, 2007 through December 31,
2008.
|
|
Pension
Benefits
|
|
|
Postretirement
Benefits
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Change
in Benefit Obligation
|
(Thousands
of dollars)
|
|
Benefit
obligation, beginning of period
|
|
$ |
819,999 |
|
|
$ |
832,980 |
|
|
$ |
294,730 |
|
|
$ |
271,510 |
|
Service
cost
|
|
|
25,577 |
|
|
|
21,050 |
|
|
|
7,198 |
|
|
|
6,392 |
|
Interest
cost
|
|
|
61,649 |
|
|
|
48,608 |
|
|
|
22,206 |
|
|
|
15,830 |
|
Plan
participants' contributions
|
|
|
- |
|
|
|
- |
|
|
|
3,299 |
|
|
|
2,882 |
|
Actuarial
(gain) loss
|
|
|
46,967 |
|
|
|
(32,697 |
) |
|
|
(21,983 |
) |
|
|
14,742 |
|
Benefits
paid
|
|
|
(66,629 |
) |
|
|
(49,942 |
) |
|
|
(26,685 |
) |
|
|
(16,626 |
) |
Benefit
obligation, end of period
|
|
$ |
887,563 |
|
|
$ |
819,999 |
|
|
$ |
278,765 |
|
|
$ |
294,730 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in Plan Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of plan assets, beginning of period
|
|
$ |
771,878 |
|
|
$ |
710,377 |
|
|
$ |
79,314 |
|
|
$ |
68,440 |
|
Actual
return on plan assets
|
|
|
(220,955 |
) |
|
|
107,305 |
|
|
|
(17,644 |
) |
|
|
5,214 |
|
Employer
contributions
|
|
|
117,597 |
|
|
|
4,138 |
|
|
|
12,444 |
|
|
|
14,925 |
|
Transfers
in
|
|
|
- |
|
|
|
- |
|
|
|
3,573 |
|
|
|
- |
|
Benefits
paid
|
|
|
(66,629 |
) |
|
|
(49,942 |
) |
|
|
- |
|
|
|
- |
|
Fair
value of assets, end of period
|
|
$ |
601,891 |
|
|
$ |
771,878 |
|
|
$ |
77,687 |
|
|
$ |
88,579 |
|
Balance
at December 31
|
|
$ |
(285,672 |
) |
|
$ |
(48,121 |
) |
|
$ |
(201,078 |
) |
|
$ |
(206,151 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current
assets
|
|
$ |
- |
|
|
$ |
10,028 |
|
|
$ |
- |
|
|
$ |
- |
|
Current
liabilities
|
|
|
(2,706 |
) |
|
|
(2,497 |
) |
|
|
- |
|
|
|
- |
|
Non-current
liabilities
|
|
|
(282,966 |
) |
|
|
(55,652 |
) |
|
|
(201,078 |
) |
|
|
(206,151 |
) |
Balance
at December 31
|
|
$ |
(285,672 |
) |
|
$ |
(48,121 |
) |
|
$ |
(201,078 |
) |
|
$ |
(206,151 |
) |
The
accumulated benefit obligation for our pension plans was $824.7 million and
$759.2 million at December 31, 2008 and 2007, respectively.
There are
no plan assets expected to be withdrawn and returned to us in 2009.
Components of Net Periodic Benefit
Cost - The
following tables set forth the components of net periodic benefit cost for our
pension and other postretirement benefit plans for the periods
indicated.
|
|
Pension
Benefits
|
|
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Components
of Net Periodic Benefit Cost
|
(Thousands
of dollars)
|
Service
cost
|
|
$ |
20,165 |
|
|
$ |
21,050 |
|
|
$ |
20,980 |
|
Interest
cost
|
|
|
49,801 |
|
|
|
48,608 |
|
|
|
43,425 |
|
Expected
return on plan assets
|
|
|
(61,268 |
) |
|
|
(58,154 |
) |
|
|
(57,586 |
) |
Amortization
of unrecognized prior service cost
|
|
|
1,551 |
|
|
|
1,486 |
|
|
|
1,511 |
|
Amortization
of net loss
|
|
|
9,548 |
|
|
|
16,139 |
|
|
|
13,314 |
|
Net
periodic benefit cost
|
|
$ |
19,797 |
|
|
$ |
29,129 |
|
|
$ |
21,644 |
|
|
|
Postretirement
Benefits
|
|
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Components
of Net Periodic Benefit Cost
|
|
(Thousands
of dollars)
|
|
Service
cost
|
|
$ |
5,675 |
|
|
$ |
6,392 |
|
|
$ |
6,332 |
|
Interest
cost
|
|
|
17,899 |
|
|
|
15,830 |
|
|
|
14,156 |
|
Expected
return on plan assets
|
|
|
(7,421 |
) |
|
|
(6,389 |
) |
|
|
(4,565 |
) |
Amortization
of unrecognized net asset at adoption
|
|
|
3,189 |
|
|
|
3,189 |
|
|
|
3,189 |
|
Amortization
of unrecognized prior service cost
|
|
|
(2,003 |
) |
|
|
(2,277 |
) |
|
|
(2,286 |
) |
Amortization
of net loss
|
|
|
10,972 |
|
|
|
9,927 |
|
|
|
9,085 |
|
Net
periodic benefit cost
|
|
$ |
28,311 |
|
|
$ |
26,672 |
|
|
$ |
25,911 |
|
Other Comprehensive Income
(Loss) - The following table sets forth the amounts recognized in other
comprehensive income (loss) for 2008 related to our pension benefits and
postretirement benefits.
|
|
Pension
Benefits
|
|
|
Postretirement
Benefits
|
|
|
|
December
31, 2008
|
|
|
December
31, 2008
|
|
|
|
(Thousands
of dollars)
|
|
Regulatory
asset gain (loss)
|
|
$ |
252,747 |
|
|
$ |
492 |
|
Net
gain (loss) arising during the period
|
|
|
(343,274 |
) |
|
|
(1,531 |
) |
Amortization
of regulatory asset
|
|
|
(11,465 |
) |
|
|
(12,911 |
) |
Amortization
of transition obligation
|
|
|
- |
|
|
|
3,986 |
|
Amortization
of prior service (cost) credit
|
|
|
1,941 |
|
|
|
(2,504 |
) |
Amortization
of loss
|
|
|
11,935 |
|
|
|
13,715 |
|
Deferred
income taxes
|
|
|
34,417 |
|
|
|
(816 |
) |
Total
recognized in other comprehensive income (loss)
|
|
$ |
(53,699 |
) |
|
$ |
431 |
|
The table
below sets forth the amounts in accumulated other comprehensive income (loss)
that had not yet been recognized as components of net periodic benefit
expense.
|
|
Pension
Benefits
|
|
|
Postretirement
Benefits
|
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands
of dollars)
|
|
Transition
obligation
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(12,724 |
) |
|
$ |
(16,711 |
) |
Prior
service credit (cost)
|
|
|
(6,852 |
) |
|
|
(8,791 |
) |
|
|
8,384 |
|
|
|
10,888 |
|
Accumulated
gain (loss)
|
|
|
(455,089 |
) |
|
|
(123,750 |
) |
|
|
(113,228 |
) |
|
|
(125,412 |
) |
Accumulated
other comprehensive income (loss)
before
regulatory assets
|
|
|
(461,941 |
) |
|
|
(132,541 |
) |
|
|
(117,568 |
) |
|
|
(131,235 |
) |
Regulatory
asset for regulated entities
|
|
|
331,882 |
|
|
|
90,600 |
|
|
|
85,619 |
|
|
|
98,038 |
|
Accumulated
other comprehensive income (loss)
after
regulatory assets
|
|
|
(130,059 |
) |
|
|
(41,941 |
) |
|
|
(31,949 |
) |
|
|
(33,197 |
) |
Deferred
income taxes
|
|
|
50,307 |
|
|
|
16,222 |
|
|
|
12,358 |
|
|
|
12,841 |
|
Accumulated
other comprehensive income (loss),
net
of tax
|
|
$ |
(79,752 |
) |
|
$ |
(25,719 |
) |
|
$ |
(19,591 |
) |
|
$ |
(20,356 |
) |
The
following table sets forth the amounts recognized in either accumulated
comprehensive income (loss) or regulatory assets expected to be recognized as
components of net periodic benefit expense in the next fiscal
year.
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
Amounts
to be recognized in 2009
|
(Thousands
of dollars)
|
Transition
obligation
|
|
$ |
- |
|
|
$ |
3,189 |
|
Prior
service credit (cost)
|
|
$ |
1,565 |
|
|
$ |
(2,003 |
) |
Net
loss
|
|
$ |
17,322 |
|
|
$ |
9,660 |
|
Actuarial Assumptions - The
following table sets forth the weighted-average assumptions used to determine
benefit obligations for the periods indicated.
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
2007
|
|
|
2008
|
|
2007
|
|
Discount
rate
|
|
6.25%
|
|
6.25%
|
|
|
6.25%
|
|
6.25%
|
|
Compensation
increase rate
|
|
4.3%
- 4.8%
|
|
3.5%
- 4.5%
|
|
|
4.3%
- 4.8%
|
|
3.5%
- 4.0%
|
|
The
following table sets forth the weighted-average assumptions used to determine
net periodic benefit costs for the periods indicated.
|
|
Pension
Benefits
|
|
Postretirement
Benefits
|
|
|
December
31,
|
|
|
December
31,
|
|
|
|
2008
|
|
2007
|
|
|
2008
|
|
2007
|
|
Discount
rate
|
|
6.25%
|
|
6.00%
|
|
|
6.25%
|
|
6.00%
|
|
Expected
long-term return on plan assets
|
|
8.50%
|
|
8.75%
|
|
|
8.50%
|
|
8.75%
|
|
Compensation
increase rate
|
|
3.5%
- 4.5%
|
|
3.5%
- 4.5%
|
|
|
3.5%
- 4.0%
|
|
3.5%
- 4.0%
|
|
We
determine our overall expected long-term rate of return on plan assets
assumption based on our review of historical returns and the economic growth
models from our consultants.
Our
discount rates for 2008 and 2007 are based on matching the amount and timing of
the projected benefit payments to a spot-rate yield curve, which provides
zero-coupon interest rates into the future. The methodology for
developing the yield curve includes selecting the bonds to be included (only
bonds rated Aa by Moody’s but excluding callable bonds, bonds with less than a
minimum issue size, yield “outliers” and various other filtering criteria to
remove unsuitable bonds). Once the bonds are selected, a best-fit
regression curve to the bond data is determined, modeling yield to maturity as a
function of years to maturity. This coupon yield curve is converted
to a spot-yield curve using the calculation technique that assumes the price of
a coupon bond for a given maturity equals the present value of the underlying
bond cash flows using zero-coupon spot rates. Once the yield curve is
developed, the projected cash flows for the plan for each year in the future are
calculated. These projected cash flows values are based on the most
recent valuation. Each annual cash flow of the plan obligations is
discounted using the yield at the appropriate point on the curve, and then the
single equivalent discount rate that would yield the same value for the cash
flow is determined.
Health Care Cost Trend Rates
- The
following table sets forth the assumed health care cost trend rates for the
periods indicated.
|
|
|
2008
|
|
2007
|
Health
care cost trend rate assumed for next year
|
|
5.0%
- 9.0%
|
|
6.6%
- 9.0%
|
Rate
to which the cost trend rate is assumed
|
|
|
|
|
|
to
decline (the ultimate trend rate)
|
|
|
5.0%
|
|
5.0%
|
Year
that the rate reaches the ultimate trend rate
|
|
|
2018
|
|
2012
|
Assumed
health care cost trend rates have a significant effect on the amounts reported
for our health care plans. A one-percentage point change in assumed
health care cost trend rates would have the following effects.
|
|
One-Percentage
|
|
|
One-Percentage
|
|
|
|
Point
Increase
|
|
|
Point
Decrease
|
|
|
|
(Thousands
of dollars)
|
|
Effect
on total of service and interest cost
|
|
$ |
1,989 |
|
|
$ |
(1,706 |
) |
Effect
on postretirement benefit obligation
|
|
$ |
19,585 |
|
|
$ |
(17,171 |
) |
Plan Assets - The following table sets
forth our pension and postretirement benefit plan weighted-average asset
allocations as of the measurement date.
|
Pension
Benefits
|
|
|
Postretirement
Benefits
|
|
|
Percentage
of Plan Assets
|
|
|
Percentage
of Plan Assets
|
|
Asset
Category
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
Corporate
bonds
|
|
|
5 |
% |
|
|
6 |
% |
|
|
25 |
% |
|
|
14 |
% |
Insurance
contracts
|
|
|
13 |
% |
|
|
11 |
% |
|
|
- |
|
|
|
- |
|
High
yield corporate bonds
|
|
|
9 |
% |
|
|
10 |
% |
|
|
- |
|
|
|
- |
|
Large-cap
value equities
|
|
|
12 |
% |
|
|
15 |
% |
|
|
14 |
% |
|
|
15 |
% |
Large-cap
growth equities
|
|
|
14 |
% |
|
|
18 |
% |
|
|
17 |
% |
|
|
22 |
% |
Mid-cap
equities
|
|
|
9 |
% |
|
|
13 |
% |
|
|
6 |
% |
|
|
8 |
% |
Small-cap
equities
|
|
|
7 |
% |
|
|
11 |
% |
|
|
12 |
% |
|
|
16 |
% |
International
equities
|
|
|
12 |
% |
|
|
16 |
% |
|
|
10 |
% |
|
|
13 |
% |
Other
(a)
|
|
|
19 |
% |
|
|
- |
|
|
|
16 |
% |
|
|
12 |
% |
Total
|
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
(a)
- Primarily money market funds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our
investment strategy is to invest plan assets in accordance with sound investment
practices that emphasize long-term fundamentals. The goal of this
strategy is to maximize investment returns while managing risk in order to meet
the plan’s current and projected financial obligations. The plan’s
investments include a diverse blend of various US and international equities,
investments in various classes of debt securities, insurance contracts and
venture capital. The target allocation for the assets of our pension
plan is as follows.
Corporate
bonds / insurance contracts
|
|
|
20 |
% |
High
yield corporate bonds
|
|
|
10 |
% |
Large-cap
value equities
|
|
|
16 |
% |
Large-cap
growth equities
|
|
|
16 |
% |
Mid-
and small-cap value equities
|
|
|
10 |
% |
Mid-
and small-cap growth equities
|
|
|
10 |
% |
International
equities
|
|
|
15 |
% |
Alternative
investments
|
|
|
2 |
% |
Venture
capital
|
|
|
1 |
% |
Total
|
|
|
100 |
% |
As part
of our risk management for the plans, minimums and maximums have been set for
each of the asset classes listed above. All investment managers for
the plan are subject to certain restrictions on the securities they purchase
and, with the exception of indexing purposes, are prohibited from owning our
stock.
Contributions - For 2008, $113.7 million
and $8.0 million of contributions were made to our pension plan and other
postretirement benefit plan, respectively. We presently anticipate
our total 2009 contributions will be $31.2 million for the pension plan and
$11.4 million for the other postretirement benefit plan.
Pension and Other Postretirement
Benefit Payments - Benefit payments for our pension and other
postretirement benefit plans for the 15-month period ending December 31, 2008,
were $66.6 million and $26.7 million, respectively. The following
table sets forth the pension benefits and postretirement benefit payments
expected to be paid in 2009-2018.
|
Pension
Benefits
|
Postretirement
Benefits
|
Benefits
to be paid in:
|
(Thousands
of dollars)
|
2009
|
$ 52,958
|
|
|
$ |
16,155
|
|
2010
|
$ 54,317
|
|
|
$ |
17,253
|
|
2011
|
$ 55,882
|
|
|
$ |
18,300
|
|
2012
|
$ 58,275
|
|
|
$ |
19,238
|
|
2013
|
$ 60,136
|
|
|
$ |
19,354
|
|
2014
through 2018
|
$ 339,437
|
|
|
$ |
113,661
|
|
The
expected benefits to be paid are based on the same assumptions used to measure
our benefit obligation at December 31, 2008, and include estimated future
employee service.
Other
Employee Benefit Plans
Thrift Plan - We have a Thrift
Plan covering all full-time employees. Employee contributions are
discretionary. We match 100 percent of employee contributions up to 6
percent of each participant’s eligible compensation, subject to certain
limits. Our contributions made to the plan were $14.7 million, $13.2
million and $12.8 million in 2008, 2007 and 2006, respectively.
Profit-Sharing Plan - We have
a profit-sharing plan for all nonbargaining unit employees hired after December
31, 2004. Nonbargaining unit employees who were employed prior to
January 1, 2005, were given a one-time opportunity to make an irrevocable
election to participate in the profit-sharing plan and not accrue any additional
benefits under our defined benefit pension plan after December 31,
2004. We plan to make a contribution to the profit-sharing plan each
quarter equal to 1 percent of each participant’s eligible compensation during
the quarter. Additional discretionary employer contributions may be
made at the end of each year. Employee contributions are not allowed
under the plan. Our contributions made to the plan were $3.2 million,
$2.7 million and $1.6 million in 2008, 2007 and 2006, respectively.
Employee Deferred Compensation Plan
- The ONEOK,
Inc. 2005 Nonqualified Deferred Compensation Plan provides select employees, as
approved by our Board of Directors, with the option to defer portions of their
compensation and provides nonqualified deferred compensation benefits that are
not available due to limitations on employer and employee contributions to
qualified defined contribution plans under the federal tax laws. Our
contributions made to the plan were not material in 2008, 2007 and
2006.
K. COMMITMENTS
AND CONTINGENCIES
Operating Leases - In July
2007, ONEOK Leasing Company, our subsidiary, gave notice of its intent to
exercise its option to purchase ONEOK Plaza on or before the end of the current
lease term set to expire on September 30, 2009. In March 2008, ONEOK
Leasing Company purchased ONEOK Plaza for a total purchase price of
approximately $48 million, which included $17.1 million for the present value of
the remaining lease payments and $30.9 million for the base purchase
price.
We lease
excess office space in ONEOK Plaza. We received rental revenue of
$2.6 million in 2008 and $2.9 million in 2007 and 2006. Estimated
minimum future rental payments to be received under existing contracts for
subleases are $1.9 million in 2009, $0.8 million in 2010 and $0.7 million in
2011.
Future
minimum lease payments under non-cancelable operating leases on a gas processing
plant, storage contracts, office space, pipeline equipment, rights-of-way and
vehicles are shown in the table below.
|
|
|
ONEOK
|
ONEOK
Partners
|
Total
|
|
|
|
(Millions
of dollars)
|
|
2009
|
|
$
88.8
|
$
18.4
|
$
107.2
|
|
2010
|
|
$
55.9
|
$
16.0
|
$
71.9
|
|
2011
|
|
$
61.2
|
$
15.5
|
$
76.7
|
|
2012
|
|
$
32.9
|
$
8.8
|
$
41.7
|
|
2013
|
|
$
25.4
|
$
2.1
|
$
27.5
|
The
amounts in the ONEOK column above include the following minimum lease payments
relating to the lease of a gas processing plant for $24.0 million in 2009, $24.2
million in 2010, and $30.6 million in 2011. We acquired the lease in
a business combination and recorded a liability for uneconomic lease
terms. The liability is accreted to rent expense in the amount of
$13.0 million per year over the term of the lease; however, the cash outflow
under the lease remains the same. The amounts in the ONEOK Partners
column above exclude intercompany payments relating to the lease of a gas
processing plant.
Environmental Liabilities - We
are subject to multiple environmental, historical and wildlife preservation laws
and regulations affecting many aspects of our present and future
operations. Regulated activities include those involving air
emissions, stormwater and wastewater discharges, handling and disposal of solid
and hazardous wastes, hazardous materials transportation, and pipeline and
facility construction. These laws and regulations require us to
obtain and comply with a wide variety of environmental clearances,
registrations, licenses, permits and other approvals. Failure to
comply with these laws, regulations, permits and licenses may expose us to
fines, penalties and/or interruptions in our operations that could be material
to our results of operations. If a leak or spill of hazardous
substances or petroleum products occurs from our lines or facilities, in the
process of transporting natural gas, NGLs, or refined products, or at any
facility that we own, operate or otherwise use, we could be held jointly and
severally liable for all resulting liabilities, including investigation and
clean-up costs, which could materially affect our results of operations and cash
flows. In addition, emission controls required under the federal
Clean Air Act and other similar federal and state laws could require unexpected
capital expenditures at our facilities. We cannot assure that
existing environmental regulations will not be revised or that new regulations
will not be adopted or become applicable to us. Revised or additional
regulations that result in increased compliance costs or additional operating
restrictions, particularly if those costs are not fully recoverable from
customers, could have a material adverse effect on our business, financial
condition and results of operations.
We own or
retain legal responsibility for the environmental conditions at 12 former
manufactured gas sites in Kansas. These sites contain potentially
harmful materials that are subject to control or remediation under various
environmental laws and regulations. A consent agreement with the KDHE
presently governs all work at these sites. The terms of the consent
agreement allow us to investigate these sites and set remediation activities
based upon the results of the investigations and
risk
analysis. Remediation typically involves the management of
contaminated soils and may involve removal of structures and monitoring and/or
remediation of groundwater.
Of the 12
sites, we have commenced soil remediation on 11 sites. Regulatory
closure has been achieved at two locations, and we have completed or are near
completion of soil remediation at nine sites. We have begun site
assessment at the remaining site where no active remediation has
occurred.
To date,
we have incurred remediation costs of $7.8 million and have accrued an
additional $4.2 million related to the sites where soil remediation has yet to
be completed. These estimates are recorded on an undiscounted
basis. For the site that is currently in the assessment phase, we
have completed some analysis but are unable at this point to accurately estimate
aggregate costs that may be required to satisfy our remedial obligations at this
site. Until the site assessment is complete and the KDHE approves the
remediation plan, we will not have complete information available to us to
accurately estimate remediation costs.
The costs
associated with these sites do not include other potential expenses that might
be incurred, such as ongoing and additional water monitoring and remediation,
unasserted property damage claims, personal injury or natural resource claims,
unbudgeted legal expenses or other costs for which we may be held liable but
with respect to which we cannot reasonably estimate an amount. As of
this date, we have no knowledge of any of these types of claims. The
foregoing estimates do not consider potential insurance recoveries, recoveries
through rates or recoveries from unaffiliated parties, to which we may be
entitled. We have filed claims with our insurance carriers relating
to these sites, and we have recovered a portion of our costs incurred to
date. We have not recorded any amounts for potential insurance
recoveries or recoveries from unaffiliated parties, and we are not recovering
any environmental amounts in rates. As more information related to
the site investigations and remediation activities becomes available, and to the
extent such amounts are expected to exceed our current estimates, additional
expenses could be recorded. Such amounts could be material to our
results of operations and cash flows depending on the remediation and number of
years over which the remediation is required to be completed.
Our
expenditures for environmental evaluation, mitigation and remediation to date
have not been significant in relation to our results of operations, and there
were no material effects upon earnings during 2008, 2007 or 2006 related to
compliance with environmental regulations.
Legal Proceedings - We are a
party to various litigation matters and claims that are in the normal course of
our operations. While the results of litigation and claims cannot be
predicted with certainty, we believe the final outcome of such matters will not
have a material adverse effect on our consolidated results of operations,
financial position or liquidity.
FERC Matter - As a result of a
transaction that was brought to the attention of one of our affiliates by a
third party, we conducted an internal review of transactions that may have
violated FERC natural gas capacity release rules or related rules and determined
that there were transactions that should be disclosed to the FERC. We
notified the FERC of this review and filed a report with the FERC regarding
these transactions in March 2008. We cooperated fully with the FERC
in its investigation of this matter and have taken steps to better ensure that
current and future transactions comply with applicable FERC regulations by
implementing a compliance plan dealing with capacity release. We
entered into a global settlement with the FERC to resolve this matter and other
FERC enforcement matters, which was approved by the FERC on January 15,
2009. The global settlement provides for a total civil penalty of
$4.5 million and approximately $2.2 million in disgorgement of profits and
interest, of which $1.7 million of the civil penalty was allocated to ONEOK
Partners. The amounts were recorded as a liability on our
Consolidated Balance Sheet as of December 31, 2008. We made the
required payments in January 2009.
L. INCOME
TAXES
The
following table sets forth our provisions for income taxes for the periods
indicated.
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Current
income taxes
|
(Thousands
of dollars)
|
|
Federal
|
|
$ |
18,833 |
|
|
$ |
100,517 |
|
|
$ |
69,698 |
|
State
|
|
|
10,047 |
|
|
|
19,063 |
|
|
|
10,312 |
|
Total
current income taxes from continuing operations
|
|
|
28,880 |
|
|
|
119,580 |
|
|
|
80,010 |
|
Deferred
income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
143,807 |
|
|
|
56,887 |
|
|
|
96,464 |
|
State
|
|
|
21,384 |
|
|
|
8,130 |
|
|
|
17,290 |
|
Total
deferred income taxes from continuing operations
|
|
|
165,191 |
|
|
|
65,017 |
|
|
|
113,754 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
provision for income taxes before discontinued operations
|
|
|
194,071 |
|
|
|
184,597 |
|
|
|
193,764 |
|
Discontinued
operations
|
|
|
- |
|
|
|
- |
|
|
|
(232 |
) |
Total
provision for income taxes
|
|
$ |
194,071 |
|
|
$ |
184,597 |
|
|
$ |
193,532 |
|
The
following table is a reconciliation of our income tax expense for the periods
indicated.
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands
of dollars)
|
|
Pretax
income from continuing operations
|
|
$ |
505,980 |
|
|
$ |
489,518 |
|
|
$ |
500,441 |
|
Federal
statutory income tax rate
|
|
|
35 |
% |
|
|
35 |
% |
|
|
35 |
% |
Provision
for federal income taxes
|
|
|
177,093 |
|
|
|
171,331 |
|
|
|
175,154 |
|
Amortization
of distribution property investment tax credit
|
|
|
(455 |
) |
|
|
(505 |
) |
|
|
(525 |
) |
State
income taxes, net of federal tax benefit
|
|
|
20,431 |
|
|
|
17,676 |
|
|
|
18,809 |
|
Other,
net
|
|
|
(2,998 |
) |
|
|
(3,905 |
) |
|
|
326 |
|
Income
tax expense
|
|
$ |
194,071 |
|
|
$ |
184,597 |
|
|
$ |
193,764 |
|
The
following table sets forth the tax effects of temporary differences that gave
rise to significant portions of the deferred tax assets and liabilities for the
periods indicated.
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Deferred
tax assets
|
|
(Thousands
of dollars)
|
|
Employee
benefits and other accrued liabilities
|
|
$ |
161,947 |
|
|
$ |
134,056 |
|
Net
operating loss carryforward
|
|
|
4,226 |
|
|
|
4,715 |
|
Other
comprehensive income
|
|
|
43,747 |
|
|
|
- |
|
Other
|
|
|
23,051 |
|
|
|
27,374 |
|
Total
deferred tax assets
|
|
|
232,971 |
|
|
|
166,145 |
|
|
|
|
|
|
|
|
|
|
Deferred
tax liabilities
|
|
|
|
|
|
|
|
|
Excess
of tax over book depreciation and depletion
|
|
|
372,123 |
|
|
|
344,601 |
|
Purchased
gas adjustment
|
|
|
20,047 |
|
|
|
9,015 |
|
Investment
in joint ventures
|
|
|
564,234 |
|
|
|
490,093 |
|
Regulatory
assets
|
|
|
180,037 |
|
|
|
115,689 |
|
Other
comprehensive income
|
|
|
- |
|
|
|
1,567 |
|
Other
|
|
|
746 |
|
|
|
2,720 |
|
Total
deferred tax liabilities
|
|
|
1,137,187 |
|
|
|
963,685 |
|
Net
deferred tax liabilities
|
|
$ |
904,216 |
|
|
$ |
797,540 |
|
At
December 31, 2008, ONEOK Partners had approximately $4.2 million of tax benefits
available related to net operating loss carryforwards, which will expire between
the years 2022 and 2027. We believe that it is more likely than not
that the tax benefits of the net operating loss carryforwards will be utilized
prior to their expiration; therefore, no valuation allowance is
necessary.
We had
income taxes receivable of approximately $77.1 million and $13.2 million at
December 31, 2008 and 2007, respectively.
M. SEGMENTS
Segment Descriptions - We have
divided our operations into four reportable business segments based on
similarities in economic characteristics, products and services, types of
customers, methods of distribution and regulatory environment. These
segments are as follows: (i) our ONEOK Partners segment gathers, processes,
transports, stores and sells natural gas and gathers, treats, fractionates,
stores, distributes and markets NGLs; (ii) our Distribution segment delivers
natural gas to residential, commercial and industrial customers, and transports
natural gas; (iii) our Energy Services segment markets natural gas to wholesale
and retail customers; and (iv) our Other segment primarily consists of the
operating and leasing operations of our headquarters building and a related
parking facility. Our Distribution segment is comprised of regulated
public utilities, and portions of our ONEOK Partners segment are also
regulated.
Accounting Policies - The
accounting policies of the segments are described in Note
A. Intersegment sales are recorded on the same basis as sales to
unaffiliated customers. Overhead costs relating to a reportable
segment have been allocated for the purpose of calculating operating
income.
Customers - The primary
customers for our ONEOK Partners segment include major and independent oil and
gas production companies, natural gas gathering and processing companies,
petrochemical, refining and NGL marketing companies, LDCs, power generating
companies, natural gas marketing companies, NGL gathering companies and propane
distributors. Our Distribution segment provides natural gas to
residential, commercial, industrial, wholesale, public authority and
transportation customers. Our Energy Services segment buys natural
gas from producers and other marketing companies and sells natural gas to LDCs,
municipalities, producers, large industrials, power generators, retail
aggregators and other marketing companies, as well as residential and small
commercial/industrial companies.
In 2008,
2007 and 2006, we had no single external customer from which we received 10
percent or more of our consolidated gross revenues.
Operating Segment Information
- The following tables set forth certain selected financial information for our
operating segments for the periods indicated.
Year
Ended December 31, 2008
|
|
ONEOK
Partners
(a)
|
|
|
Distribution
(b)
|
|
|
Energy
Services
|
|
|
Other
and Eliminations
|
|
|
Total
|
|
|
|
(Thousands
of dollars)
|
|
Sales
to unaffiliated customers
|
|
$ |
6,975,320 |
|
|
$ |
2,177,615 |
|
|
$ |
7,001,296 |
|
|
$ |
3,202 |
|
|
$ |
16,157,433 |
|
Intersegment
revenues
|
|
|
744,886 |
|
|
|
7 |
|
|
|
584,507 |
|
|
|
(1,329,400 |
) |
|
|
- |
|
Total
revenues
|
|
$ |
7,720,206 |
|
|
$ |
2,177,622 |
|
|
$ |
7,585,803 |
|
|
$ |
(1,326,198 |
) |
|
$ |
16,157,433 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
margin
|
|
$ |
1,140,659 |
|
|
$ |
680,971 |
|
|
$ |
110,716 |
|
|
$ |
3,181 |
|
|
$ |
1,935,527 |
|
Operating
costs
|
|
|
371,797 |
|
|
|
375,328 |
|
|
|
35,593 |
|
|
|
(5,806 |
) |
|
|
776,912 |
|
Depreciation
and amortization
|
|
|
124,765 |
|
|
|
116,782 |
|
|
|
921 |
|
|
|
1,459 |
|
|
|
243,927 |
|
Gain
or (loss) on sale of assets
|
|
|
713 |
|
|
|
(21 |
) |
|
|
1,500 |
|
|
|
124 |
|
|
|
2,316 |
|
Operating
income
|
|
$ |
644,810 |
|
|
$ |
188,840 |
|
|
$ |
75,702 |
|
|
$ |
7,652 |
|
|
$ |
917,004 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
earnings from
investments
|
|
$ |
101,432 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
101,432 |
|
Investments
in unconsolidated
affiliates
|
|
$ |
755,492 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
755,492 |
|
Minority
interests in
consolidated
subsidiaries
|
|
$ |
5,941 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
1,073,428 |
|
|
$ |
1,079,369 |
|
Total
assets
|
|
$ |
7,254,272 |
|
|
$ |
3,063,374 |
|
|
$ |
1,752,256 |
|
|
$ |
1,056,160 |
|
|
$ |
13,126,062 |
|
Capital
expenditures
|
|
$ |
1,253,853 |
|
|
$ |
169,049 |
|
|
$ |
62 |
|
|
$ |
50,172 |
|
|
$ |
1,473,136 |
|
(a)
- Our ONEOK Partners segment has regulated and non-regulated
operations. Our ONEOK Partners segment's regulated operations had
revenues of $439.3 million, net margin of $334.1 million and operating
income of $158.8 million.
|
|
(b)
- All of our Distribution segment's operations are
regulated.
|
|
Year
Ended December 31, 2007
|
|
ONEOK
Partners
(a)
|
|
|
Distribution
(b)
|
|
|
Energy
Services
|
|
|
Other
and Eliminations
|
|
|
Total
|
|
|
|
(Thousands
of dollars)
|
|
Sales
to unaffiliated customers
|
|
$ |
5,204,794 |
|
|
$ |
2,099,056 |
|
|
$ |
6,170,084 |
|
|
$ |
3,480 |
|
|
$ |
13,477,414 |
|
Intersegment
revenues
|
|
|
626,764 |
|
|
|
7 |
|
|
|
459,319 |
|
|
|
(1,086,090 |
) |
|
|
- |
|
Total
revenues
|
|
$ |
5,831,558 |
|
|
$ |
2,099,063 |
|
|
$ |
6,629,403 |
|
|
$ |
(1,082,610 |
) |
|
$ |
13,477,414 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
margin
|
|
$ |
895,893 |
|
|
$ |
663,648 |
|
|
$ |
247,402 |
|
|
$ |
3,165 |
|
|
$ |
1,810,108 |
|
Operating
costs
|
|
|
337,356 |
|
|
|
377,778 |
|
|
|
39,920 |
|
|
|
6,456 |
|
|
|
761,510 |
|
Depreciation
and amortization
|
|
|
113,704 |
|
|
|
111,615 |
|
|
|
2,147 |
|
|
|
498 |
|
|
|
227,964 |
|
Gain
or (loss) on sale of assets
|
|
|
1,950 |
|
|
|
(56 |
) |
|
|
- |
|
|
|
15 |
|
|
|
1,909 |
|
Operating
income
|
|
$ |
446,783 |
|
|
$ |
174,199 |
|
|
$ |
205,335 |
|
|
$ |
(3,774 |
) |
|
$ |
822,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
earnings from
investments
|
|
$ |
89,908 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
89,908 |
|
Investments
in unconsolidated
affiliates
|
|
$ |
756,260 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
756,260 |
|
Minority
interests in
consolidated
subsidiaries
|
|
$ |
5,802 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
796,162 |
|
|
$ |
801,964 |
|
Total
assets
|
|
$ |
6,112,065 |
|
|
$ |
3,045,249 |
|
|
$ |
1,549,012 |
|
|
$ |
355,708 |
|
|
$ |
11,062,034 |
|
Capital
expenditures
|
|
$ |
709,858 |
|
|
$ |
162,044 |
|
|
$ |
158 |
|
|
$ |
11,643 |
|
|
$ |
883,703 |
|
(a)
- Our ONEOK Partners segment has regulated and non-regulated
operations. Our ONEOK Partners segment's regulated operations had
revenues of $344.3 million, net margin of $273.7 million and operating
income of $122.4 million.
|
|
(b)
- All of our Distribution segment's operations are
regulated.
|
|
Year
Ended December 31, 2006
|
|
ONEOK
Partners
(a)
|
|
|
Distribution
(b)
|
|
|
Energy
Services
|
|
|
Other
and Eliminations
|
|
|
Total
|
|
|
|
(Thousands
of dollars)
|
|
Sales
to unaffiliated customers
|
|
$ |
4,142,546 |
|
|
$ |
1,958,192 |
|
|
$ |
5,846,258 |
|
|
$ |
(26,670 |
) |
|
$ |
11,920,326 |
|
Intersegment
revenues
|
|
|
595,702 |
|
|
|
7 |
|
|
|
489,549 |
|
|
|
(1,085,258 |
) |
|
|
- |
|
Total
revenues
|
|
$ |
4,738,248 |
|
|
$ |
1,958,199 |
|
|
$ |
6,335,807 |
|
|
$ |
(1,111,928 |
) |
|
$ |
11,920,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
margin
|
|
$ |
843,548 |
|
|
$ |
599,797 |
|
|
$ |
273,818 |
|
|
$ |
4,821 |
|
|
$ |
1,721,984 |
|
Operating
costs
|
|
|
325,774 |
|
|
|
371,460 |
|
|
|
42,464 |
|
|
|
1,069 |
|
|
|
740,767 |
|
Depreciation
and amortization
|
|
|
122,045 |
|
|
|
110,858 |
|
|
|
2,149 |
|
|
|
491 |
|
|
|
235,543 |
|
Gain
on sale of assets
|
|
|
115,483 |
|
|
|
18 |
|
|
|
- |
|
|
|
1,027 |
|
|
|
116,528 |
|
Operating
income
|
|
$ |
511,212 |
|
|
$ |
117,497 |
|
|
$ |
229,205 |
|
|
$ |
4,288 |
|
|
$ |
862,202 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
earnings from
investments
|
|
$ |
95,883 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
95,883 |
|
Investments
in unconsolidated
affiliates
|
|
$ |
748,879 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
748,879 |
|
Minority
interests in
consolidated
subsidiaries
|
|
$ |
5,606 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
795,039 |
|
|
$ |
800,645 |
|
Total
assets
|
|
$ |
4,921,717 |
|
|
$ |
2,940,514 |
|
|
$ |
2,023,663 |
|
|
$ |
505,188 |
|
|
$ |
10,391,082 |
|
Capital
expenditures
|
|
$ |
201,746 |
|
|
$ |
159,026 |
|
|
$ |
- |
|
|
$ |
15,534 |
|
|
$ |
376,306 |
|
(a)
- Our ONEOK Partners segment has regulated and non-regulated
operations. Our ONEOK Partners segment's regulated operations had
revenues of $335.9 million, net margin of $261.8 million and operating
income of $240.1 million, including $113.9 million from a gain on sale of
assets, for the year ended December 31, 2006.
|
|
(b)
- All of our Distribution segment's operations are
regulated.
|
|
N. STOCK-BASED
COMPENSATION
Equity
Compensation Plan
The
ONEOK, Inc. Equity Compensation Plan provides for the granting of stock-based
compensation, including incentive stock options, non-statutory stock options,
stock bonus awards, restricted stock awards, restricted stock unit awards,
performance stock awards and performance unit awards to eligible employees and
the granting of stock awards to non-employee directors. We have
reserved a total of approximately 5.0 million shares of common stock for
issuance under the plan. In December 2008, we amended the Equity
Compensation Plan to allow for the deferral of awards granted in stock or cash,
in accordance with Internal Revenue Code section 409A
requirements. This deferral option is applicable for certain awards
granted in 2006 and later, and vesting after 2008.
Restricted Stock Incentive
Units - Restricted stock incentive units may be granted to key employees
with ownership of the common stock underlying the incentive unit vesting over a
period determined by the Committee. Awards granted to date vest over
a three-year period. Awards granted in 2008, 2007 and 2006 entitle
the grantee to receive shares of our common stock. Awards granted in
2005 entitled the grantee to receive two-thirds of the grant in our common stock
(equity awards) and one-third of the grant in cash (liability
awards). The equity awards are measured at fair value as if they were
vested and issued on the grant date, reduced by expected dividend payments and
adjusted for estimated forfeitures. The portion of the
grants that are settled in cash are classified as liability awards with fair
value based on the fair market value of our common stock, reduced by expected
dividend payments and adjusted for estimated forfeitures, at each reporting
date. No dividends are paid on the restricted stock incentive
units. Compensation expense is recognized on a straight-line basis
over the vesting period of the award.
Performance Unit Awards - Performance unit awards
may be granted to key employees. The shares of our common stock
underlying the performance units vest at the expiration of a period determined
by the Committee if certain performance criteria are met by
us. Performance units granted to date vest at the expiration of a
three-year period. Upon vesting, a holder of performance units is
entitled to receive a number of shares of our common stock equal to a percentage
(0 percent to 200 percent) of the performance units granted based on our total
shareholder return over the vesting period, compared with the total shareholder
return of a peer group of other energy companies over the same
period. Compensation expense is recognized on a straight-line basis
over the period of the award.
If paid,
the performance unit awards granted in 2008, 2007 and 2006 entitle the grantee
to receive the grant in shares of our common stock. Under Statement
123R, our 2008, 2007 and 2006 performance unit awards are equity awards with a
market-based condition, which results in the compensation cost for these awards
being recognized over the requisite service period, provided that the requisite
service period is fulfilled, regardless of when, if ever, the market condition
is satisfied. The fair value of these performance units was estimated
on the grant date based on a Monte Carlo model. The compensation expense
on these awards will only be adjusted for changes in forfeitures.
The
performance unit awards granted in 2005 entitled the grantee to receive
two-thirds of the grant in shares of our common stock (equity awards) and
one-third of the grant in cash (liability awards). The fair values of
these performance units that were classified as equity awards were calculated as
of the date of grant were not adjusted upon adoption of Statement
123R. The fair values of the one-third liability portion of the
performance units were estimated at each reporting date based on a Monte Carlo
model.
Long-Term
Incentive Plan
The
ONEOK, Inc. Long-Term Incentive Plan (the LTIP) provides for the granting of
stock awards similar to those described above with respect to the Equity
Compensation Plan. We have reserved a total of approximately 7.8
million shares of common stock for issuance under the plan. The
maximum number of shares for which options or other awards may be granted to any
employee during any year is 300,000.
Options - Stock options may be
granted that are not exercisable until a fixed future date or in
installments. Options issued to date become void upon voluntary
termination of employment other than retirement. In the event of
retirement or involuntary termination, the optionee may exercise the option
within a period determined by the Executive Compensation Committee (the
Committee) and stated in the option. In the event of death, the
option may be exercised by the personal representative of the optionee within a
period to be determined by the Committee and stated in the option. A
portion of the options issued to date
can be
exercised after one year from grant date and an option must be exercised no
later than 10 years after grant date. Effective January 1, 2007, we
eliminated the restored option feature for outstanding stock option
grants.
Stock
Compensation Plan for Non-Employee Directors
The
ONEOK, Inc. Stock Compensation Plan for Non-Employee Directors (the DSCP)
provides for the granting of stock options, stock bonus awards, including
performance unit awards, restricted stock awards and restricted stock unit
awards. Under the DSCP, these awards may be granted by the Committee
at any time, until grants have been made for all shares authorized under the
DSCP. We have reserved a total of 700,000 shares of common stock for
issuance under the DSCP. The maximum number of shares of common stock
which can be issued to a participant under the DSCP during any year is
20,000. No performance unit awards or restricted stock awards have
been made to non-employee directors under the DSCP.
Options - Options may be
granted to non-employee directors on the same terms as those granted under the
LTIP.
General
Effective
January 1, 2006, we adopted Statement 123R. See Note A for additional
information. For all awards outstanding, we used a forfeiture rate
ranging from zero percent to 13 percent based on historical forfeitures under
our share-based payment plans. We use a combination of issuances from
treasury stock and repurchases in the open market to satisfy our share-based
payment obligations.
Compensation
cost expensed for our share-based payment plans described below was $13.1
million, $12.0 million and $17.6 million 2008, 2007 and 2006, respectively,
which is net of $8.3 million, $7.5 million and $11.2 million of tax benefits,
respectively. No compensation cost was capitalized for 2008, 2007 and
2006.
Cash
received from the exercise of awards under all share-based payment arrangements
was $3.8 million and $7.4 million for 2008 and 2007,
respectively. The actual tax benefit realized for the anticipated tax
deductions of the exercise of share-based payment arrangements totaled $1.4
million and $4.6 million for 2008 and 2007, respectively. No cash was
used to settle the equity portion of the restricted stock unit and performance
unit awards granted under share-based payment arrangements.
Stock
Option Activity
The
following table sets forth the stock option activity for employees and
non-employee directors for the periods indicated.
|
|
Number
of
|
|
|
Weighted
|
|
|
|
Shares
|
|
|
Average
Price
|
|
Outstanding
December 31, 2007
|
|
|
953,146 |
|
|
$ |
24.69 |
|
Exercised
|
|
|
(176,215 |
) |
|
$ |
25.72 |
|
Expired
|
|
|
(2,625 |
) |
|
$ |
28.69 |
|
Outstanding
December 31, 2008
|
|
|
774,306 |
|
|
$ |
24.44 |
|
|
|
|
|
|
|
|
|
|
Exercisable
December 31, 2008
|
|
|
774,306 |
|
|
$ |
24.44 |
|
The
aggregate intrinsic value in the table below represents the total pre-tax
intrinsic value, based on our year-end closing stock price of $29.12, that would
have been received by the option holders had all option holders exercised their
options as of December 31, 2008.
|
|
|
Stock
Options Outstanding and Exercisable
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
Average
|
|
|
Weighted
|
|
|
Intrinsic
|
|
Range
of
|
|
|
Number
|
|
|
Remaining
|
|
|
Average
|
|
|
Value
|
|
Exercise
Prices
|
|
|
of
Awards
|
|
|
Life
(yrs)
|
|
|
Exercise
Price
|
|
|
(in
000's)
|
|
$14.58
to $21.87
|
|
|
376,485
|
|
|
3.04
|
|
|
$ |
16.98
|
|
|
$ |
4,571 |
|
$21.88
to $32.82
|
|
|
179,666
|
|
|
1.86
|
|
|
$ |
24.69
|
|
|
$ |
796 |
|
$32.83
to $43.67
|
|
|
218,155
|
|
|
2.15
|
|
|
$ |
37.11
|
|
|
$ |
- |
|
The fair
value of each restored option was estimated on the date of grant using the
Black-Scholes model and the assumptions in the table below.
|
|
December
31, 2006
|
|
Volatility
(a)
|
|
15.43%
to 25.23%
|
|
Dividend
Yield
|
|
3.24%
to 4.00%
|
|
Risk-free
Interest Rate
|
|
4.39%
to 5.18%
|
|
(a)
- Volatility was based on historical volatility over twelve
months
using
daily stock price
observations.
|
The
weighted-average period of outstanding options is 2.5 years. As of
December 31, 2008, all stock options were fully vested and
expensed. The following table sets forth various statistics relating
to our stock option activity.
|
|
December
31, 2008
|
|
|
December
31, 2007
|
|
|
December
31, 2006
|
|
Weighted-average
grant date fair value of options restored (per share)
|
|
(a)
|
|
|
(a)
|
|
|
$ |
5.57 |
|
Intrinsic
value of options exercised (thousands of dollars)
|
|
$ |
3,652 |
|
|
$ |
12,129 |
|
|
$ |
10,246 |
|
Fair
value of options granted (thousands of dollars)
|
|
(a)
|
|
|
(a)
|
|
|
$ |
1,990 |
|
(a)
- Due to our elimination of the restored option feature effective January
1, 2007, no grants were restored in 2007 or 2008.
|
|
Restricted
Stock Unit Activity
The total
fair value of shares vested during 2008 was $5.9 million. As of
December 31, 2008, there was $5.5 million of total unrecognized compensation
cost related to our nonvested restricted stock unit awards, which is expected to
be recognized over a weighted-average period of 1.5 years. The
following tables set forth activity and various statistics for the equity
portion of the restricted stock unit awards.
|
|
Number
of
|
|
|
Weighted
|
|
|
|
Shares
|
|
|
Average
Price
|
|
Nonvested
December 31, 2007
|
|
|
461,627 |
|
|
$ |
31.56 |
|
Granted
|
|
|
53,550 |
|
|
$ |
47.44 |
|
Released
to participants
|
|
|
(86,076 |
) |
|
$ |
25.34 |
|
Forfeited
|
|
|
(1,969 |
) |
|
$ |
38.16 |
|
Nonvested
December 31, 2008
|
|
|
427,132 |
|
|
$ |
34.78 |
|
|
|
December
31, 2008
|
|
|
December
31, 2007
|
|
|
December
31, 2006
|
|
Weighted-average
grant date fair value (per share)
|
|
$ |
43.22 |
|
|
$ |
36.82 |
|
|
$ |
25.98 |
|
Fair
value of shares granted (thousands of dollars)
|
|
$ |
2,314 |
|
|
$ |
9,733 |
|
|
$ |
3,761 |
|
The
following table sets forth activity for the liability portion of the restricted
stock unit awards.
|
|
Number
of
|
|
|
Weighted
|
|
|
|
Shares
|
|
|
Average
Price
|
|
Nonvested
December 31, 2007
|
|
|
40,583 |
|
|
$ |
25.07 |
|
Released
to participants
|
|
|
(40,583 |
) |
|
$ |
25.19 |
|
Forfeited
|
|
|
- |
|
|
$ |
- |
|
Nonvested
December 31, 2008
|
|
|
- |
|
|
$ |
- |
|
Performance
Unit Activity
The total
fair value of shares vested during 2008 was $14.9 million. As of
December 31, 2008, there was $14.5 million of total unrecognized compensation
cost related to the nonvested performance unit awards, which is expected to be
recognized
over a
weighted-average period of 1.1 years. The following tables set forth
activity and various statistics related to the performance unit equity awards
and the assumptions used in the valuations of the 2008, 2007 and 2006 grants at
the grant date.
|
|
Number
of
|
|
|
Weighted
|
|
|
|
Units
|
|
|
Average
Price
|
|
Nonvested
December 31, 2007
|
|
|
936,916 |
|
|
$ |
29.63 |
|
Granted
|
|
|
387,125 |
|
|
$ |
47.44 |
|
Released
to participants (a)
|
|
|
(211,517 |
) |
|
$ |
25.48 |
|
Forfeited
|
|
|
(20,975 |
) |
|
$ |
38.32 |
|
Nonvested
December 31, 2008
|
|
|
1,091,549 |
|
|
$ |
36.58 |
|
(a)
- Performance awards granted in 2005 and released in 2008 were adjusted
with
a
150 percent performance factor; for the equity awards, this resulted in
an
additional
105,760 shares released to participants.
|
|
|
|
2008
|
|
|
2007
|
|
2006
|
Volatility
(a)
|
|
22.50%
|
|
|
20.30%
|
|
18.80%
|
Dividend
Yield
|
|
3.20%
|
|
|
3.79%
|
|
3.70%
|
Risk-free
Interest Rate
|
|
2.46%
|
|
|
4.80%
|
|
4.32%
|
(a)
- Volatility was based on historical volatility over three years using
daily stock price
observations.
|
|
|
December
31, 2008
|
|
|
December
31, 2007
|
|
|
December
31, 2006
|
|
Weighted-average
grant date fair value (per share)
|
|
$ |
43.88 |
|
|
$ |
37.58 |
|
|
$ |
25.98 |
|
Fair
value of shares granted (thousands of dollars)
|
|
$ |
16,987 |
|
|
$ |
12,366 |
|
|
$ |
12,444 |
|
The
following tables set forth activity for the performance unit liability awards
and the assumptions used in the valuations at the end of each period
indicated.
|
|
Number
of
|
|
|
Weighted
|
|
|
|
Units
|
|
|
Average
Price
|
|
Nonvested
December 31, 2007
|
|
|
106,139 |
|
|
$ |
25.48 |
|
Released
to participants (a)
|
|
|
(105,758 |
) |
|
$ |
25.48 |
|
Forfeited
|
|
|
(381 |
) |
|
$ |
26.57 |
|
Nonvested
December 31, 2008
|
|
|
- |
|
|
$ |
- |
|
(a)
- Performance awards granted in 2005 and released in 2008 were adjusted
with
a
150 percent performance factor; for the liability awards, this resulted in
an
additional
52,880 liability units released to participants.
|
|
|
|
2008
|
|
|
2007
|
|
2006
|
Volatility
(a)
|
|
(b)
|
|
|
21.80%
|
|
20.30%
|
Dividend
Yield
|
|
(b)
|
|
|
3.05%
|
|
3.62%
|
Risk-free
Interest Rate
|
|
(b)
|
|
|
3.07%
|
|
4.74%
|
(a)
- Volatility was based on historical volatility over three years using
daily stock price observations.
|
(b)
- Nonvested balance at December 31, 2008 was
zero.
|
Employee
Stock Purchase Plan
We have
reserved a total of 4.8 million shares of common stock for issuance under our
ONEOK, Inc. Employee Stock Purchase Plan (the ESPP). Subject to
certain exclusions, all full-time employees are eligible to participate in the
ESPP. Employees can choose to have up to 10 percent of their annual
base pay withheld to purchase our common stock, subject to terms and limitations
of the plan. The Committee may allow contributions to be made by
other means, provided that in no event will contributions from all means exceed
10 percent of the employee’s annual base pay. The purchase price of
the stock is 85 percent of the lower of its grant date or exercise date market
price. Approximately 52 percent, 59 percent and 63 percent of
employees participated in the plan in 2008, 2007 and 2006,
respectively. Under the plan, we sold 297,864 shares at $24.41 in
2008, 217,369 shares at $36.85 per share in 2007, and 340,364 shares at $22.57
per share in 2006.
Employee
Stock Award Program
Under our
Employee Stock Award Program, we issued, for no consideration, to all eligible
employees (all full-time employees and employees on short-term disability) one
share of our common stock when the per-share closing price of our common stock
on the NYSE was for the first time at or above $26 per share, and we have issued
and will continue to issue, for no consideration, one additional share of our
common stock to all eligible employees when the closing price on the NYSE is for
the first time at or above each one dollar increment above $26 per
share. We have reserved a total of 300,000 shares of common stock for
issuance under this program.
There
were no shares issued to employees under this program in 2008. Shares
issued to employees under this program totaled 44,099 and 40,705 for the years
ended December 31, 2007 and 2006, respectively. Compensation expense
related to the Employee Stock Award Plan was $2.2 million and $1.6 million in
2007 and 2006, respectively.
Deferred Compensation Plan for
Non-Employee Directors
The
ONEOK, Inc. Nonqualified Deferred Compensation Plan for Non-Employee Directors
provides our directors, who are not our employees, the option to defer all or a
portion of their compensation for their service on our Board of
Directors. Under the plan, directors may elect either a cash deferral
option or a phantom stock option. Under the cash deferral option,
directors may defer the receipt of all or a portion of their annual retainer
and/or meeting fees, plus accrued interest. Under the phantom stock
option, directors may defer all or a portion of their annual retainer and/or
meeting fees and receive such fees on a deferred basis in the form of shares of
common stock under our Long-Term Incentive Plan or Equity Compensation
Plan. Shares are distributed to non-employee directors at the fair
market value of our common stock at the date of distribution. In
December 2008, we amended the Deferred Compensation Plan for Non-Employee
Directors in accordance with Internal Revenue Code section 409A
requirements.
O. UNCONSOLIDATED
AFFILIATES
Investments in Unconsolidated
Affiliates - The following table sets forth our investments in
unconsolidated affiliates for the periods indicated.
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
Ownership
|
|
|
December
31, |
|
|
|
December
31, |
|
|
|
|
Interest
|
|
|
2008
|
|
|
|
2007
|
|
|
|
|
|
|
|
(Thousands
of dollars)
|
|
|
Northern
Border Pipeline
|
|
|
50
%
|
|
|
$ |
392,601 |
|
|
|
$ |
418,982 |
|
|
Bighorn
Gas Gathering, L.L.C.
|
|
|
49
%
|
|
|
|
97,289 |
|
|
|
|
97,716 |
|
|
Fort
Union Gas Gathering
|
|
|
37
%
|
|
|
|
108,642 |
|
|
|
|
85,197 |
|
|
Lost
Creek Gathering Company, L.L.C. (a)
|
|
|
35
%
|
|
|
|
77,773 |
|
|
|
|
75,612 |
|
|
Other
|
|
Various
|
|
|
|
79,187 |
|
|
|
|
78,753 |
|
|
Investments
in unconsolidated affiliates
|
|
|
|
|
|
$ |
755,492 |
|
(b)
|
|
$ |
756,260 |
|
(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
- ONEOK Partners is entitled to receive an incentive allocation of
earnings from third-party gathering services revenue recognized by Lost
Creek Gathering Company, L.L.C. As a result of the incentive, ONEOK
Partners’ share of Lost Creek Gathering Company, L.L.C.'s income exceeds
its 35 percent ownership interest.
|
(b)
- Equity method goodwill (Note E) was $185.6 million at December 31, 2008
and 2007.
|
|
|
|
|
|
|
|
Equity Earnings from Investments
- The
following table sets forth our equity earnings from investments for the periods
indicated. All amounts in the table below are equity earnings from
investments in our ONEOK Partners segment.
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands
of dollars)
|
|
Northern
Border Pipeline (a)
|
|
$ |
65,912 |
|
|
$ |
62,008 |
|
|
$ |
72,393 |
|
Bighorn
Gas Gathering, L.L.C.
|
|
|
8,195 |
|
|
|
7,416 |
|
|
|
8,223 |
|
Fort
Union Gas Gathering
|
|
|
14,172 |
|
|
|
9,681 |
|
|
|
9,030 |
|
Lost
Creek Gathering Company, L.L.C.
|
|
|
5,365 |
|
|
|
4,790 |
|
|
|
5,363 |
|
Other
|
|
|
7,788 |
|
|
|
6,013 |
|
|
|
874 |
|
Equity
Earnings From Investments
|
|
$ |
101,432 |
|
|
$ |
89,908 |
|
|
$ |
95,883 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
- For the first three months of 2006, ONEOK Partners included 70 percent
of Northern Border Pipeline’s income in equity earnings from
investments. After the sale of a 20 percent interest in Northern
Border Pipeline in April 2006, ONEOK Partners included 50 percent of
Northern Border Pipeline’s income in equity earnings from investments
(Note B).
|
|
Unconsolidated Affiliates Financial
Information - Summarized combined financial information of our
unconsolidated affiliates is presented below.
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(Thousands
of dollars)
|
|
Balance
Sheet
|
|
|
|
|
|
|
Current
assets
|
|
$ |
106,833 |
|
|
$ |
102,805 |
|
Property,
plant and equipment, net
|
|
$ |
1,777,350 |
|
|
$ |
1,724,330 |
|
Other
noncurrent assets
|
|
$ |
27,547 |
|
|
$ |
25,882 |
|
Current
liabilities
|
|
$ |
279,996 |
|
|
$ |
79,593 |
|
Long-term
debt
|
|
$ |
543,894 |
|
|
$ |
717,301 |
|
Other
noncurrent liabilities
|
|
$ |
14,360 |
|
|
$ |
10,278 |
|
Accumulated
other comprehensive income (loss)
|
|
$ |
(5,708 |
) |
|
$ |
(2,441 |
) |
Owners'
equity
|
|
$ |
1,079,188 |
|
|
$ |
1,048,286 |
|
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands
of dollars)
|
|
Income
Statement
|
|
|
|
|
|
|
|
|
|
Operating
revenue
|
|
$ |
415,552 |
|
|
$ |
404,399 |
|
|
$ |
386,448 |
|
Operating
expenses
|
|
$ |
179,380 |
|
|
$ |
172,997 |
|
|
$ |
159,452 |
|
Net
income
|
|
$ |
209,915 |
|
|
$ |
184,434 |
|
|
$ |
183,732 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
paid to us
|
|
$ |
118,010 |
|
|
$ |
103,785 |
|
|
$ |
123,427 |
|
P. EARNINGS
PER SHARE INFORMATION
The
following table sets forth the computation of basic and diluted EPS from
continuing operations for the periods indicated.
|
Year
Ended December 31, 2008
|
|
|
|
|
|
|
|
Per
Share
|
|
|
Income
|
|
|
Shares
|
|
Amount
|
Basic
EPS from continuing operations
|
(Thousands,
except per share amounts)
|
Income
from continuing operations available for common stock
|
|
$ |
311,909 |
|
|
|
104,369 |
|
|
$ |
2.99 |
|
Diluted
EPS from continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
and other dilutive securities
|
|
|
- |
|
|
|
1,391 |
|
|
|
|
|
Income
from continuing operations available for common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
and
common stock equivalents
|
|
$ |
311,909 |
|
|
|
105,760 |
|
|
$ |
2.95 |
|
|
|
Year
Ended December 31, 2007
|
|
|
|
|
|
|
|
Per
Share
|
|
|
Income
|
|
|
Shares
|
|
Amount
|
Basic
EPS from continuing operations
|
(Thousands,
except per share amounts)
|
Income
from continuing operations available for common stock
|
|
$ |
304,921 |
|
|
|
107,346 |
|
|
$ |
2.84 |
|
Diluted
EPS from continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of other dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
and other dilutive securities
|
|
|
- |
|
|
|
1,952 |
|
|
|
|
|
Income
from continuing operations available for common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
and
common stock equivalents
|
|
$ |
304,921 |
|
|
|
109,298 |
|
|
$ |
2.79 |
|
|
|
Year
Ended December 31, 2006
|
|
|
|
|
|
|
|
Per
Share
|
|
|
Income
|
|
|
Shares
|
|
Amount
|
Basic
EPS from continuing operations
|
(Thousands,
except per share amounts)
|
Income
from continuing operations available for common stock
|
|
$ |
306,677 |
|
|
|
112,006 |
|
|
$ |
2.74 |
|
Diluted
EPS from continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect
of other dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mandatory
convertible units
|
|
|
- |
|
|
|
629 |
|
|
|
|
|
Options
and other dilutive securities
|
|
|
- |
|
|
|
1,842 |
|
|
|
|
|
Income
from continuing operations available for common stock
|
|
|
|
|
|
|
|
|
|
|
|
|
and
common stock equivalents
|
|
$ |
306,677 |
|
|
|
114,477 |
|
|
$ |
2.68 |
|
There
were 64,989, 4,601 and 66,463 option shares excluded from the calculation of
diluted EPS for 2008, 2007 and 2006, respectively, since their inclusion would
be anti-dilutive.
Q. ONEOK
PARTNERS
Ownership Interest in ONEOK Partners - See Note B
for discussion of the acquisition of the additional general partner interest in
ONEOK Partners.
In April
2006, we received newly created Class B limited partner units from ONEOK
Partners. As of April 7, 2007, the Class B limited partner units are
no longer subordinated to distributions on ONEOK Partners’ common units and
generally have the same voting rights as the common units and are entitled to
receive increased quarterly distributions and distributions on liquidation equal
to 110 percent of the distributions paid with respect to the common
units. On June 21, 2007, we, as the sole holder of ONEOK Partners
Class B limited partner units, waived our right to receive the increased
quarterly distributions on the Class B units for the period April 7, 2007,
through December 31, 2007, and continuing thereafter until we give
ONEOK
Partners no less than 90 days advance notice that we have withdrawn our
waiver. Any such withdrawal of the waiver will be effective with
respect to any distribution on the Class B units declared or paid on or after 90
days following delivery of the notice.
Under the
ONEOK Partners’ partnership agreement and in conjunction with the issuance of
additional common units by ONEOK Partners, we, as the general partner, are
required to make equity contributions in order to maintain our representative
general partner interest.
Our
ownership interest in ONEOK Partners is shown in the table below for the periods
presented.
|
|
December
31,
|
|
December
31,
|
|
December
31,
|
|
|
2008
|
|
2007
|
|
2006
|
General
partner interest
|
|
2.00%
|
|
|
2.00%
|
|
|
2.00%
|
|
Limited
partner interest
|
|
45.70%
|
(a)
|
|
43.70%
|
(b)
|
|
43.70%
|
(b)
|
Total
ownership interest
|
|
47.70%
|
|
|
45.70%
|
|
|
45.70%
|
|
(a)
- Represents 5.9 million common units and approximately 36.5 million Class
B units, which are convertible, at our option, into common
units.
|
(b)
- Represents 0.5 million common units and approximately 36.5 million Class
B units, which are convertible, at our option, into common
units.
|
In March
2008, we purchased from ONEOK Partners, in a private placement, an additional
5.4 million of ONEOK Partners’ common units for a total purchase price of
approximately $303.2 million. In addition, ONEOK Partners completed a
public offering of 2.5 million common units at $58.10 per common unit and
received net proceeds of $140.4 million after deducting underwriting discounts
but before offering expenses. In conjunction with ONEOK Partners’
private placement and public offering of common units, ONEOK Partners GP
contributed $9.4 million to ONEOK Partners in order to maintain its 2 percent
general partner interest. We and ONEOK Partners GP funded these
amounts with available cash and short-term borrowings.
In April
2008, ONEOK Partners sold an additional 128,873 common units at $58.10 per
common unit to the underwriters of the public offering upon their partial
exercise of their option to purchase additional common units to cover
over-allotments. ONEOK Partners received net proceeds of
approximately $7.2 million from the sale of these common units after deducting
underwriting discounts but before offering expenses. In conjunction
with the partial exercise by the underwriters, ONEOK Partners GP contributed
$0.2 million to ONEOK Partners in order to maintain its 2 percent general
partner interest.
Cash Distributions - Under the
ONEOK Partners’ partnership agreement, distributions are made to the partners
with respect to each calendar quarter in an amount equal to 100 percent of
available cash. Available cash generally consists of all cash
receipts adjusted for cash disbursements and net changes to cash
reserves. Available cash will generally be distributed 98 percent to
limited partners and 2 percent to the general partner. The general
partner’s percentage interest in quarterly distributions is increased after
certain specified target levels are met. Under the incentive
distribution provisions, the general partner receives:
·
|
15
percent of amounts distributed in excess of $0.605 per
unit;
|
·
|
25
percent of amounts distributed in excess of $0.715 per unit;
and
|
·
|
50
percent of amounts distributed in excess of $0.935 per
unit.
|
ONEOK
Partners’ income is allocated to the general and limited partners in accordance
with their respective partnership ownership percentages. The effect
of any incremental income allocations for incentive distributions that are
allocated to the general partner is calculated after the income allocation for
the general partner’s partnership interest and before the income allocation to
the limited partners.
The
following table shows ONEOK Partners’ general partner and incentive
distributions related to the periods indicated.
|
|
Years
Ended December 31,
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
(Thousands
of dollars)
|
General
partner distributions
|
|
$ |
9,456 |
|
|
$ |
7,842 |
|
|
$ |
6,228 |
|
Incentive
distributions
|
|
|
76,042 |
|
|
|
50,627 |
|
|
|
31,102 |
|
Total
distributions to general partner
|
|
$ |
85,498 |
|
|
$ |
58,469 |
|
|
$ |
37,330 |
|
The
quarterly distributions paid by ONEOK Partners to limited partners in the first,
second, third and fourth quarters of 2008 were $1.025 per unit, $1.04 per unit,
$1.06 per unit, and $1.08 per unit, respectively.
In
January 2009, ONEOK Partners declared a cash distribution of $1.08 per unit
payable in the first quarter. On February 13, 2009, we received the
related incentive distribution of $20.3 million for the fourth quarter of 2008,
which is included in the table above.
Relationship - We own 47.7
percent of ONEOK Partners and consolidate ONEOK Partners in our consolidated
financial statements; however, we are restricted from the assets and cash flows
from ONEOK Partners except for our distributions. Distributions are
declared quarterly by ONEOK Partners’ general partner based on the terms of its
partnership agreement. For the years ended December 31, 2008, 2007
and 2006, cash distributions declared from ONEOK Partners to us totaled $266.1
million, $207.4 million and $145.1 million, respectively. See Note M
for more information on ONEOK Partners results.
Affiliate Transactions - We
have certain transactions with our ONEOK Partners affiliate and its
subsidiaries, which comprise our ONEOK Partners segment.
ONEOK
Partners sells natural gas from its natural gas gathering and processing
operations to our Energy Services segment. In addition, a large
portion of ONEOK Partners’ revenues from its natural gas pipelines businesses
are from our Energy Services and Distribution segments, which utilize ONEOK
Partners’ natural gas transportation and storage services. ONEOK
Partners also purchases natural gas from our Energy Services segment for its
natural gas liquids operations and its gathering and processing
operations.
ONEOK
Partners has certain contractual rights to the Bushton Plant through a
Processing and Services Agreement with us, which sets out the terms for
processing and related services we provide at the Bushton Plant through
2012. ONEOK Partners has contracted for all of the capacity of the
Bushton Plant from OBPI. In exchange, ONEOK Partners pays us for all
direct costs and expenses of the Bushton Plant, including reimbursement of a
portion of our obligations under equipment leases covering the Bushton
Plant.
We
provide a variety of services to our affiliates, including cash management and
financial services, employee benefits provided through our benefit plans,
administrative services provided by our employees and management, insurance and
office space leased in our headquarters building and other field
locations. Where costs are specifically incurred on behalf of an
affiliate, the costs are billed directly to the affiliate by us. In
other situations, the costs may be allocated to the affiliates through a variety
of methods, depending upon the nature of the expenses and the activities of the
affiliates. For example, a service that applies equally to all
employees is allocated based upon the number of employees in each
affiliate. However, an expense benefiting the consolidated company
but having no direct basis for allocation is allocated by the modified Distrigas
method, a method using a combination of ratios that include gross plant and
investment, earnings before interest and taxes and payroll expense.
The
following table shows transactions with ONEOK Partners for the periods
shown.
|
|
Years
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(Thousands
of dollars)
|
|
Revenues
|
|
$ |
744,886 |
|
|
$ |
626,764 |
|
|
$ |
595,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost
of sales and fuel
|
|
$ |
107,983 |
|
|
$ |
89,792 |
|
|
$ |
177,367 |
|
Administrative
and general expenses
|
|
|
191,798 |
|
|
|
171,741 |
|
|
|
175,270 |
|
Interest
expense
|
|
|
- |
|
|
|
- |
|
|
|
21,372 |
|
Total
expenses
|
|
$ |
299,781 |
|
|
$ |
261,533 |
|
|
$ |
374,009 |
|
See
“Ownership Interest in ONEOK Partners” above for additional discussion of our
purchase of common units and ONEOK Partners GP’s additional general partner
contributions in March and April 2008.
R. QUARTERLY
FINANCIAL DATA (UNAUDITED)
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
Year
Ended December 31, 2008
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
|
(Thousands
of dollars, except per share amounts)
|
|
Total
Revenues
|
|
$ |
4,902,076 |
|
|
$ |
4,172,866 |
|
|
$ |
4,239,246 |
|
|
$ |
2,843,245 |
|
Net
Margin
|
|
$ |
585,912 |
|
|
$ |
420,828 |
|
|
$ |
455,026 |
|
|
$ |
473,761 |
|
Operating
Income
|
|
$ |
333,123 |
|
|
$ |
173,012 |
|
|
$ |
192,179 |
|
|
$ |
218,690 |
|
Net
Income
|
|
$ |
143,837 |
|
|
$ |
41,865 |
|
|
$ |
58,033 |
|
|
$ |
68,174 |
|
Earnings
per share from continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
1.38 |
|
|
$ |
0.40 |
|
|
$ |
0.56 |
|
|
$ |
0.65 |
|
Diluted
|
|
$ |
1.36 |
|
|
$ |
0.39 |
|
|
$ |
0.55 |
|
|
$ |
0.65 |
|
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
Year
Ended December 31, 2007
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
|
(Thousands
of dollars, except per share amounts)
|
|
Total
Revenues
|
|
$ |
3,806,208 |
|
|
$ |
2,876,241 |
|
|
$ |
2,809,997 |
|
|
$ |
3,984,968 |
|
Net
Margin
|
|
$ |
564,850 |
|
|
$ |
367,699 |
|
|
$ |
340,160 |
|
|
$ |
537,399 |
|
Operating
Income
|
|
$ |
328,301 |
|
|
$ |
135,745 |
|
|
$ |
102,770 |
|
|
$ |
255,727 |
|
Net
Income
|
|
$ |
152,880 |
|
|
$ |
35,203 |
|
|
$ |
13,914 |
|
|
$ |
102,924 |
|
Earnings
per share from continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
1.38 |
|
|
$ |
0.32 |
|
|
$ |
0.13 |
|
|
$ |
0.99 |
|
Diluted
|
|
$ |
1.36 |
|
|
$ |
0.31 |
|
|
$ |
0.13 |
|
|
$ |
0.98 |
|
ITEM
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
Evaluation
of Disclosure Controls and Procedures
We have
established disclosure controls and procedures to ensure that information
required to be disclosed by us, including our consolidated entities, in the
reports that we file or submit under the Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the SEC’s rules
and forms. Under the supervision and with the
participation
of senior management, including our Chief Executive Officer (“Principal
Executive Officer”) and our Chief Financial Officer (“Principal Financial
Officer”), we evaluated our disclosure controls and procedures, as such term is
defined under Rule 13a-15(e) promulgated under the Exchange
Act. Based on this evaluation, our Principal Executive Officer and
our Principal Financial Officer concluded that our disclosure controls and
procedures were effective as of December 31, 2008.
Management’s
Report on Internal Control Over Financial Reporting
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in Exchange Act Rule
13a-15(f). Under the supervision and with the participation of our
management, including our Principal Executive Officer and Principal Financial
Officer, we evaluated the effectiveness of our internal control over financial
reporting based on the framework in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Because of inherent limitations, internal
control over financial reporting may not prevent or detect
misstatements. Also, projections of any evaluation of effectiveness
to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate. Based on our evaluation under
that framework and applicable SEC rules, our management concluded that our
internal control over financial reporting was effective as of December 31,
2008.
Our
internal control over financial reporting as of December 31, 2008, has been
audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which is included herein (Item
8).
Changes
in Internal Controls Over Financial Reporting
We have
made no changes in our internal controls over financial reporting (as defined in
Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended
December 31, 2008, that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
ITEM
9B. OTHER INFORMATION
Not
applicable.
PART
III.
ITEM
10.
|
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
|
Directors
of the Registrant
Information
concerning our directors is set forth in our 2009 definitive Proxy Statement and
is incorporated herein by this reference.
Executive
Officers of the Registrant
Information
concerning our executive officers is included in Part I, Item 1. Business, of
this Annual Report on Form 10-K.
Compliance
with Section 16(a) of the Exchange Act
Information
on compliance with Section 16(a) of the Exchange Act is set forth in our 2009
definitive Proxy Statement and is incorporated herein by this
reference.
Code
of Ethics
Information
concerning the code of ethics, or code of business conduct, is set forth in our
2009 definitive Proxy Statement and is incorporated herein by this
reference.
Nominating
Committee Procedures
Information
concerning the nominating committee procedures is set forth in our 2009
definitive Proxy Statement and is incorporated herein by this
reference.
Audit
Committee
Information
concerning the Audit Committee is set forth in our 2009 definitive Proxy
Statement and is incorporated herein by this reference.
Audit
Committee Financial Expert
Information
concerning the Audit Committee Financial Expert is set forth in our 2009
definitive Proxy Statement and is incorporated herein by this
reference.
Information
on executive compensation is set forth in our 2009 definitive Proxy Statement
and is incorporated herein by this reference.
ITEM
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND
RELATED STOCKHOLDER MATTERS
Security
Ownership of Certain Beneficial Owners
Information
concerning the ownership of certain beneficial owners is set forth in our 2009
definitive Proxy Statement and is incorporated herein by this
reference.
Security
Ownership of Management
Information
on security ownership of directors and officers is set forth in our 2009
definitive Proxy Statement and is incorporated herein by this
reference.
Equity
Compensation Plan Information
The
following table sets forth certain information concerning our equity
compensation plans as of December 31, 2008.
|
|
|
|
|
|
|
|
Number
of Securities
|
|
|
|
|
|
|
|
|
Remaining
Available For
|
|
|
Number
of Securities
|
Weighted-Average
|
Future
Issuance Under
|
|
|
to
be Issued Upon
|
Exercise
Price of
|
Equity
Compensation
|
|
|
Exercise
of Outstanding
|
Outstanding
Options,
|
Plans
(Excluding
|
|
Options,
Warrants and Rights
|
Warrants
and Rights
|
Securities
in Column (a))
|
Plan
Category
|
(a)
|
(b)
|
(c)
|
Equity
compensation plans
|
|
|
|
|
|
|
|
|
|
approved
by security holders (1)
|
|
2,300,035
|
|
|
$31.71
|
|
|
6,053,331
|
|
Equity
compensation plans
|
|
|
|
|
|
|
|
|
|
not
approved by security holders (2)
|
|
179,133
|
|
|
$27.03
|
(3)
|
|
4,153,578
|
|
Total
|
|
2,479,168
|
|
|
$31.37
|
|
|
10,206,909
|
|
|
|
|
|
|
|
|
|
|
|
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(1)
-
|
Includes
shares granted under our Employee Stock Purchase Plan, Employee Stock
Award Program, stock options, restricted stock incentive units and
performance unit awards granted under our Long-Term Incentive Plan and
Equity Compensation Plan. For a brief description of the
material features of these plans, see Note N of the Notes to Consolidated
Financial Statements in this Annual Report on Form 10-K. Column
(c) includes 1,408,443, 155,648, 2,120,616 and 2,368,624 shares available
for future issuance under our Employee Stock Purchase Plan, Employee Stock
Award Program, Long-Term Incentive Plan and Equity Compensation Plan,
respectively.
|
(2)
-
|
Includes
our Employee Non-Qualified Deferred Compensation Plan, Deferred
Compensation Plan for Non-Employee Directors and Stock Compensation Plan
for Non-Employee Directors. For a brief description of the
material features of these plans, see Note N of the Notes to Consolidated
Financial Statements in this Annual Report on Form 10-K. Column
(c) includes 503,602, 2,707,003 and 942,973 shares available for future
issuance under our Stock Compensation Plan for Non-Employee Directors,
Thrift Plan and Profit Sharing Plan, respectively.
|
(3)
-
|
Compensation
deferred into our common stock under our Employee Non-Qualified Deferred
Compensation Plan and Deferred Compensation Plan for Non-Employee
Directors is distributed to participants at fair market value on the date
of distribution. The price used for these plans to calculate
the weighted-average exercise price in the table is $29.12, which
represents the year-end closing price of our common stock on the
NYSE.
|
ITEM
13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE
|
Information
on certain relationships and related transactions and director independence is
set forth in our 2009 definitive Proxy Statement and is incorporated herein by
this reference.
ITEM
14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information
concerning the principal accountant’s fees and services is set forth in our 2009
definitive Proxy Statement and is incorporated herein by this
reference.
PART
IV.
ITEM
15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(1) Financial
Statements
|
Page No.
|
(a)
|
Reports
of Independent Registered Public Accounting Firms
|
67-68
|
(b)
|
Consolidated
Statements of Income for the years ended
December
31, 2008, 2007 and 2006
|
69
|
(c)
|
Consolidated
Balance Sheets as of December 31, 2008 and 2007
|
70-71
|
(d)
|
Consolidated
Statements of Cash Flows for the years ended
December
31, 2008, 2007 and 200
|
73
|
(e)
|
Consolidated
Statements of Shareholders’ Equity and Comprehensive
Income
for the years ended December 31, 2008, 2007 and 2006
|
74-75
|
(f)
|
Notes
to Consolidated Financial Statements
|
76-117
|
(2) Financial
Statement Schedules
All
schedules have been omitted because of the absence of conditions under which
they are required.
(3) Exhibits
|
3.4
|
Amended
and Restated Bylaws of ONEOK, Inc. (incorporated by reference from Exhibit
99.1 to Form 8-K filed January 20,
2009).
|
|
3.5
|
Amended
and Restated Certificate of Incorporation of ONEOK, Inc. dated May 15,
2008 (incorporated by reference from Exhibit 3.1 to Form 8-K filed May 19,
2008).
|
|
3.6
|
Certificate
of Correction form dated November 5, 2008 (incorporated by reference from
Exhibit 4.2 to Registration Statement on Form S-3 filed November 21,
2008).
|
|
4
|
Certificate
of Designation for Convertible Preferred Stock of WAI, Inc. (now ONEOK,
Inc.) filed November 21, 2008 (incorporated by reference from Exhibit 4.2
to Registration Statement on Form S-3 filed November 21, 2008, Commission
File No. 333-155593).
|
|
4.1
|
Certificate
of Designation for Series C Participating Preferred Stock of ONEOK, Inc.
filed November 21, 2008 (incorporated by reference from Exhibit No. 4.2 to
Registration Statement on Form S-3 filed November 21,
2008).
|
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4.2
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Form
of Common Stock Certificate (incorporated by reference from Exhibit 1 to
Registration Statement on Form 8-A filed November 21,
1997).
|
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4.3
|
Indenture,
dated September 24, 1998, between ONEOK, Inc. and Chase Bank of Texas
(incorporated by reference from Exhibit 4.1 to Registration Statement on
Form S-3 filed August 26, 1998, Commission File No.
333-62279).
|
|
4.4
|
Indenture
dated December 28, 2001, between ONEOK, Inc. and SunTrust Bank
(incorporated by reference from Exhibit 4.1 to Amendment No. 1 to
Registration Statement on Form S-3 filed December 28, 2001, Commission
File No. 333-65392).
|
|
4.5
|
First
Supplemental Indenture dated September 24, 1998, between ONEOK, Inc. and
Chase Bank of Texas (incorporated by reference from Exhibit 5(a) to Form
8-K filed September 24, 1998).
|
|
4.6
|
Second
Supplemental Indenture dated September 25, 1998, between ONEOK, Inc. and
Chase Bank of Texas (incorporated by reference from Exhibit 5(b) to Form
8-K filed September 24,
1998).
|
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4.7
|
Third
Supplemental Indenture dated February 8, 1999, between ONEOK, Inc. and
Chase Bank of Texas (incorporated by reference from Exhibit 4 to Form 8-K
filed February 8, 1999).
|
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4.8
|
Fourth
Supplemental Indenture dated February 17, 1999, between ONEOK, Inc. and
Chase Bank of Texas (incorporated by reference from Exhibit 4.5 to
Registration Statement on Form S-3 filed April 15, 1999, Commission File
No. 333-76375).
|
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4.12
|
Eighth
Supplemental Indenture dated April 6, 2001, between ONEOK, Inc. and The
Chase Manhattan Bank (incorporated by reference from Exhibit 4.9 to
Registration Statement on Form S-3 filed July 19, 2001, Commission File
No. 333-65392).
|
|
4.13
|
First
Supplemental Indenture, dated as of January 28, 2003, between ONEOK, Inc.
and SunTrust Bank (incorporated by reference from Exhibit 4.22 to
Registration Statement on Form 8-A/A filed January 31,
2003).
|
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4.14
|
Second
Supplemental Indenture, dated June 17, 2005, between ONEOK, Inc. and
SunTrust Bank (incorporated by reference from Exhibit 4.1 to Form 8-K
filed June 17, 2005).
|
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4.15
|
Third
Supplemental Indenture, dated June 17, 2005, between ONEOK, Inc. and
SunTrust Bank (incorporated by reference from Exhibit 4.3 to Form 8-K
filed June 17, 2005).
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4.16
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Form
of Senior Note Due 2008 (included in Exhibit
4.13).
|
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4.17
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Form
of 5.20 percent Notes Due 2015 (included in Exhibit
4.14).
|
|
4.18
|
Form
of 6.00 percent Notes due 2035 (included in Exhibit
4.15).
|
4.20 Not
used.
|
4.24
|
Amended
and Restated Rights Agreement dated as of February 5, 2003, between ONEOK,
Inc. and UMB Bank, N.A., as Rights Agent (incorporated by reference from
Exhibit 1 to Registration Statement on Form 8-A/A (Amendment No. 1) filed
February 6, 2003).
|
|
10
|
ONEOK,
Inc. Long-Term Incentive Plan (incorporated by reference from Exhibit
10(a) to Form 10-K for the fiscal year ended December 31, 2001, filed
March 14, 2002).
|
|
10.1
|
ONEOK,
Inc. Stock Compensation Plan for Non-Employee Directors (incorporated by
reference from Exhibit 99 to Form S-8 filed January 25,
2001).
|
|
10.2
|
ONEOK,
Inc. Supplemental Executive Retirement Plan terminated and frozen December
31, 2004 (incorporated by reference from Exhibit 10.1 to Form 8-K filed on
December 20, 2004).
|
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10.3
|
ONEOK,
Inc. 2005 Supplemental Executive Retirement Plan, as amended and restated,
dated December 18, 2008.
|
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10.4
|
Form
of Termination Agreement between ONEOK, Inc. and ONEOK, Inc. executives,
as amended, dated January 1, 2003 (incorporated by reference from Exhibit
10.3 to Form 10-K for the fiscal year ended December 31, 2002, filed March
10, 2003).
|
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10.5
|
Form
of Indemnification Agreement between ONEOK, Inc. and ONEOK, Inc. officers
and directors, as amended, dated January 1, 2003 (incorporated by
reference from Exhibit 10.4 to Form 10-K for the fiscal year ended
December 31, 2002, filed March 10,
2003).
|
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10.6
|
ONEOK,
Inc. Annual Officer Incentive Plan (incorporated by reference from Exhibit
10(f) to Form 10-K for the fiscal year ended December 31, 2001, filed
March 14, 2002).
|
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10.7
|
ONEOK,
Inc. Employee Nonqualified Deferred Compensation Plan, as amended and
restated December 16, 2004 (incorporated by reference from Exhibit 10.3 to
Form 8-K filed December 20, 2004).
|
|
10.8
|
ONEOK,
Inc. 2005 Nonqualified Deferred Compensation Plan, as amended and
restated, dated December 18, 2008.
|
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10.9
|
ONEOK,
Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and
restated, dated December 18, 2008.
|
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10.17
|
$1,200,000,000
Amended and Restated Credit Agreement dated as of July 14, 2006 among
ONEOK, Inc., as the Borrower, Bank of America, N.A., as Administrative
Agent, Swing Line Lender and L/C Issuer, Citibank, N.A., as L/C Issuer,
and the Lenders party hereto (incorporated by reference from Exhibit 10.1
to the Form 10-Q for the quarter ended June 30, 2006, filed August 4,
2006).
|
|
10.21
|
First
Amendment, dated as of September 26, 2008, to the Amended and Restated
Credit Agreement, dated as of July 14, 2006, among ONEOK, Inc., as the
Borrower, Bank of America, N.A., as the Administrative Agent, Swing Line
Lender and L/C Issuer, Citibank N.A., as L/C Issuer and the financial
institutions named therein as lenders (incorporated by reference from
Exhibit 10.1 to our Form 10-Q filed November 6,
2008).
|
|
10.32
|
Services
Agreement among ONEOK, Inc. and its affiliates and Northern Border
Partners, L.P. and Northern Border Intermediate Limited Partnership
executed April 6, 2006, but effective as of April 1, 2006 (incorporated by
reference from Exhibit 10.1 to our Form 8-K filed April 12,
2006).
|
|
10.33
|
Third
Amended and Restated Agreement of Limited Partnership of ONEOK Partners,
L.P. dated as of September 15, 2006 (incorporated by reference to Exhibit
3.1 to ONEOK Partners, L.P.’s Form 8-K filed on September 19, 2006 (File
No. 1-12202)).
|
|
10.37
|
ONEOK,
Inc. Profit Sharing Plan dated January 1, 2005 (incorporated by reference
from Exhibit 99 to Registration Statement on Form S-8 filed December 30,
2004).
|
|
10.38
|
ONEOK,
Inc. Employee Stock Purchase Plan as amended and restated effective as of
December 20, 2007 (incorporated by reference from Exhibit 4.2 to
Registration Statement on Form S-8 filed August 4,
2008).
|
|
10.39
|
Form
of Non-Statutory Stock Option Agreement (incorporated by reference from
Exhibit 10.1 to Form 10-Q for the quarter ended September 30, 2004, filed
November 3, 2004).
|
|
10.44
|
ONEOK,
Inc. Equity Compensation Plan, as amended and restated, dated December 18,
2008.
|
|
10.45
|
Form
of Restricted Unit Award Agreement (incorporated by reference from Exhibit
10.45 to Form 10-K filed February 28,
2007).
|
|
10.46
|
Form
of Performance Unit Award Agreement (incorporated by reference from
Exhibit 10.46 to Form 10-K filed February 28,
2007).
|
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10.47
|
First
Amendment to Letter of Credit Reimbursement Agreement by and between KBC
Bank N.V. and ONEOK, Inc. dated December 19, 2005 (incorporated by
reference from Exhibit 10.47 to our Form 10-K for the year ended December
31, 2006, filed March 1, 2007).
|
|
10.48
|
Amended
and Restated Revolving Credit Agreement dated March 30, 2007, among ONEOK
Partners, L.P., as Borrower, the lenders from time to time party thereto,
SunTrust Bank, as Administrative Agent, Wachovia Bank, National
Association, as Syndication Agent, and BMO Capital Markets, Barclays Bank
PLC, and Citibank, N.A., as Co-Documentation Agents (incorporated by
reference from Exhibit 10.1 to our Form 10-Q filed May 2,
2007).
|
|
10.49
|
Purchase
Agreement dated June 27, 2007, by and between ONEOK, Inc. (the “Issuer”),
and Bank of America, N.A., acting through Banc of America Securities LLC
(“Agent”) as agent (incorporated by reference from Exhibit 10.1 to our
Form 10-Q filed August 3, 2007).
|
|
10.50
|
Thrift
Plan for Employees of ONEOK, Inc. and Subsidiaries as amended and restated
effective as of January 1, 2008 (incorporated by reference from Exhibit
4.3 to Registration Statement on Form S-8 filed August 4,
2008).
|
|
10.51
|
Amendment
No. 1 to Third Amended and Restated Agreement of Limited Partnership of
ONEOK Partners, L.P. dated July 20, 2007 (incorporated by reference to
Exhibit 3.1 to ONEOK Partners, L.P.’s Form 10-Q filed on August 3, 2007
(File No. 1-12202)).
|
|
10.52
|
$400,000,000
364-Day Revolving Credit Agreement dated as of August 6, 2008, among
ONEOK, Inc., as Borrower, Bank of America, N.A., as the Administrative
Agent and Swing Line Lender, the lenders named therein, Barclays Bank,
PLC, BNP Paribas, Suntrust Bank and UBS Loan Finance LLC as
Co-Documentation Agents, and Banc of America Securities LLC as sole Lead
Arranger and sole Book Manager (incorporated by reference from Exhibit
10.4 to the Form 10-Q for the quarter ended June 30, 2008, filed August 6,
2008).
|
|
10.53
|
Common
Unit Purchase Agreement between ONEOK, Inc. and ONEOK Partners, L.P. dated
March 11, 2008 (incorporated by reference from Exhibit 1.1 to our Form 8-K
filed March 12, 2008).
|
|
10.54
|
Form
of Performance Unit Award Agreement dated January 15,
2009.
|
|
10.55
|
Form
of Restricted Unit Stock Bonus Award Agreement dated January 15,
2009.
|
|
12
|
Computation
of Ratio of Earnings to Fixed Charges for the years ended December 31,
2008, 2007, 2006, 2005 and 2004.
|
|
16.1
|
Letter
from KPMG LLP dated May 2, 2007, to the Securities and Exchange Commission
regarding change in certifying accountant (incorporated by reference to
Exhibit 16.1 to our Form 8-K filed on May 2,
2007).
|
|
21
|
Required
information concerning the registrant’s
subsidiaries.
|
|
23.1
|
Consent
of Independent Registered Public Accounting Firm - PricewaterhouseCoopers
LLP.
|
|
23.2
|
Consent
of Independent Registered Public Accounting Firm - KPMG
LLP.
|
|
31.1
|
Certification
of John W. Gibson pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
|
|
31.2
|
Certification
of Curtis L. Dinan pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
|
|
32.1
|
Certification
of John W. Gibson pursuant to 18 U.S.C. Section 1350 as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant
to Rule 13a-14(b)).
|
|
32.2
|
Certification
of Curtis L. Dinan pursuant to 18 U.S.C. Section 1350 as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 (furnished only pursuant
to Rule 13a-14(b)).
|
Pursuant
to the requirements of Section 13 or 15(d) of the Exchange Act, the registrant
has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
ONEOK,
Inc.
Registrant
Date:
February 24,
2009 By:
/s/ Curtis L.
Dinan
Curtis L.
Dinan
Senior
Vice President,
Chief
Financial Officer and Treasurer
(Principal
Financial Officer)
Pursuant
to the requirements of the Exchange Act, this report has been signed below by
the following persons on behalf of the registrant and in the capacities
indicated on this 24th day of February 2009.
/s/
John W. Gibson
|
|
/s/
David L. Kyle
|
John
W. Gibson
|
|
David
L. Kyle
|
Chief
Executive Officer
|
|
Chairman
of the
|
|
|
Board
of Directors
|
|
|
|
/s/
Caron A. Lawhorn
|
|
/s/
James C. Day
|
Caron
A. Lawhorn
|
|
James
C. Day
|
Senior
Vice President and
|
|
Director
|
Chief
Accounting Officer
|
|
|
|
|
|
/s/
Julie H. Edwards
|
|
/s/
William L. Ford
|
Julie
H. Edwards
|
|
William
L. Ford
|
Director
|
|
Director
|
|
|
|
/s/
Bert H. Mackie
|
|
/s/
Jim W. Mogg
|
Bert
H. Mackie
|
|
Jim
W. Mogg
|
Director
|
|
Director
|
|
|
|
/s/
Pattye L. Moore
|
|
/s/
Gary D. Parker
|
Pattye
L. Moore
|
|
Gary
D. Parker
|
Director
|
|
Director
|
|
|
|
/s/
Eduardo A. Rodriguez
|
|
/s/
David J. Tippeconnic
|
Eduardo
A. Rodriguez
|
|
David
J. Tippeconnic
|
Director
|
|
Director
|
|
|
|
/s/
Mollie B. Williford
|
|
|
Mollie
B. Williford
|
|
|
Director
|
|
|